To see the other types of publications on this topic, follow the link: Offshore drilling unit.
Journal articles on the topic 'Offshore drilling unit'
Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles
Consult the top 50 journal articles for your research on the topic 'Offshore drilling unit.'
Next to every source in the list of references, there is an 'Add to bibliography' button. Press on it, and we will generate automatically the bibliographic reference to the chosen work in the citation style you need: APA, MLA, Harvard, Chicago, Vancouver, etc.
You can also download the full text of the academic publication as pdf and read online its abstract whenever available in the metadata.
Browse journal articles on a wide variety of disciplines and organise your bibliography correctly.
1
Slomski, Stephen, and Vitoon Vivatrat. "Risk Analysis for Arctic Offshore Operations." Marine Technology and SNAME News 23, no. 02 (April 1, 1986): 123–30. http://dx.doi.org/10.5957/mt1.1986.23.2.123.
Full textAbstract:
The ice conditions in the Beaufort Sea are very variable, particularly in the deeper water regions. This variability greatly influences the probability of success or failure of an offshore operation. For example, a summer exploratory program conducted from a floating drilling unit may require a period of 60 to 100 days on station. The success of such a program depends on:the time when the winter ice conditions deteriorate sufficiently for the drilling unit to move on station;the number of summer invasions by the arctic ice pack, forcing the drilling unit to abandon station;the rate at which first-year ice grows to the ice thickness limit of the supporting icebreakers; andthe extent of arctic pack expansion during the fall and early winter. In general, the ice conditions are so variable that, even with good planning, the chance of failure of an offshore operation will not be negligible. Contingency planning for such events is therefore necessary. This paper presents a risk analysis procedure which can greatly benefit the planning of an offshore operation. A floating drilling program and a towing and installation operation for a fixed structure are considered to illustrate the procedure.
2
Mrozowska, Alicja. "Implementation of the Contingency Plan On Offshore Units Including Mobile Offshore Drilling Units." Annual of Navigation 23, no. 1 (December 1, 2016): 235–50. http://dx.doi.org/10.1515/aon-2016-0017.
Full textAbstract:
Abstract The article discusses practical application of the contingency plan (called also the emergency response plan) to the risks that may occur on an offshore unit. The author, based on her own professional experience, discusses the plan and illustrates its use in practice based on selected elements of the plan for mobile offshore drilling units engaged in the exploration of resources beneath the seabed. The paper discusses the requirements of Directive 2013/30/EU, which is includes obligation to implement the contingency plan relating to offshore units, in order to prevent accidents resulting from offshore oil and gas operations.
3
Kim, Teak-Keon, Seul-Kee Kim, and Jae-Myung Lee. "Dynamic Response of Drill Floor Considering Propagation of Blast Pressure Subsequent to Blowout." Applied Sciences 10, no. 24 (December 10, 2020): 8841. http://dx.doi.org/10.3390/app10248841.
Full textAbstract:
Explosions and fire have very critical safety hazard impacts on offshore oil and gas facilities since they are mostly located in remote areas and could induce serious environmental issues. Explosion risk assessment and structure blast analysis are essential for these production facilities, and research studies have been carried out. Explosion due to blowout during drilling operation is also a critical risk for drilling units, and this has not been researched much until the accident of the drilling unit in the Gulf of Mexico in 2010. This paper provides the risk and evaluation of explosion and structure under blast pressure during the drilling operation, whereas previous research studies have mainly been interested in process plants. This study suggests weight saving in drilling units through the consideration of the actual behavior of gas explosion. Weight saving is the priority of offshore unit design due to payload. This research also gives guidelines to select the material-grade-appropriate anti-explosion system through the comparison of several materials by design and result.
4
AIZAWA, Sadamichi. "Consideration on the recent technical tendency of mobil offshore drilling unit." Journal of the Japanese Association for Petroleum Technology 50, no. 2 (1985): 131–40. http://dx.doi.org/10.3720/japt.50.131.
Full text
5
Michael, Farid Y., and David B. Waller. "A New Monohull Form Development as Applied to an Offshore Drilling Unit." Marine Technology and SNAME News 23, no. 01 (January 1, 1986): 55–73. http://dx.doi.org/10.5957/mt1.1986.23.1.55.
Full textAbstract:
A new monohull form has been developed specifically in an attempt to combine certain advantages of the semisubmersible and conventional ship shape drilling vessel into a vessel of unique design. The new hull form represents a well-balanced workable design particularly suited to ships where seakeeplng, environmental operability and overall cost-effectiveness are the primary requirements. The basic advantages of the new monohull form when applied to a drillship are as follows:excellent motion characteristics (motions approach those of a comparable semisubmersible);economical advantages in hull fabrication due to the use of straight line framing and developable surfaces;high payload-to-displacement ratio compared with a semisubmersible;large usable deck area compared with a conventional drillship;safety—substantially improved intact stability characteristics, thus incorporating a major advantage of a semisubmersible; anda hull configuration that provides good structural integrity when compared with a semisubmersible.
6
Johnson, Ralph E., and H. Paul Cojeen. "An Investigation into the Loss of the Mobile Offshore Drilling Unit Ocean Ranger." Marine Technology and SNAME News 22, no. 02 (April 1, 1985): 109–25. http://dx.doi.org/10.5957/mt1.1985.22.2.109.
Full textAbstract:
The loss of all 84 persons aboard the mobile offshore drilling unit (MODU) Ocean Ranger on February 15, 1982 and 123 of the 212 persons aboard the MODU Alexander L. Kielland on March 27, 1980 are dramatic examples of MODU accidents. One of the purposes of this paper is to describe the investigative process undertaken by the National Transportation Safety Board (NTSB), the U.S. Coast Guard and the Canadian Royal Commission to determine the cause of the capsizing and sinking of the Ocean Ranger. In that regard, the NTSB analysis and findings are presented. A number of other MODU casualties are summarized in order to put this casualty into perspective. The responsibility for the safe operations of these complex and expensive platforms must be shared among regulators, vessel owners, drilling contractors, operators and labor organizations. The paper examines the national and international rules and regulations that are in place relating to design, construction and operation of MODU's. The NTSB recommendations are put into this shared-responsibility framework.
7
Mohan, Poonam, and A. P. Shashikala. "Stability Assessment of Drill Ship Using Probabilistic Damage Stability Analysis." Transactions on Maritime Science 8, no. 2 (October 21, 2019): 180–97. http://dx.doi.org/10.7225/toms.v08.n02.003.
Full textAbstract:
Drill ship is a ship-shaped structure with a drilling unit at its center and with oil compartments, which is moored and kept in position using anchors. These ships should be capable of working in deep sea for a long time, hence affected by harsh ocean environment. Drill units are said to have greater heave motion, and the height of the derrick influences the vessel’s stability. MARPOL Oil Outflow Analysis is performed for damaged crude oil carriers or tankers and Mobile offshore drilling units (MODU) in damaged condition. In the present study, probabilistic analysis is performed on drill ship to understand its stability behavior under damaged condition. Stability assessments are carried out by considering single and multiple damage locations. Oil outflow analysis is carried out for different damage cases of oil tank. Probabilistic damage assessment is done for load cases up to 50% flooding, to obtain stability charts. These charts will be useful to understand variations in stability parameters under damaged conditions.
8
Hughes, Sarah A., Jonathan Naile, Meg Pinza, Collin Ray, Brian Hester, Julia Baum, William Gardiner, Waverly Kallestad, and Louis Brzuzy. "Characterization of Miscellaneous Effluent Discharges from a Mobile Offshore Drilling Unit to the Marine Environment." Environmental Toxicology and Chemistry 38, no. 12 (October 17, 2019): 2811–23. http://dx.doi.org/10.1002/etc.4581.
Full text
9
Cherednichenko, Oleksandr, Serhiy Serbin, and Marek Dzida. "Investigation of the Combustion Processes in the Gas Turbine Module of an FPSO Operating on Associated Gas Conversion Products." Polish Maritime Research 26, no. 4 (December 1, 2019): 149–56. http://dx.doi.org/10.2478/pomr-2019-0077.
Full textAbstract:
Abstract In this paper, we consider the issue of thermo-chemical heat recovery of waste heat from gas turbine engines for the steam conversion of associated gas for offshore vessels. Current trends in the development of offshore infrastructure are identified, and the composition of power plants for mobile offshore drilling units and FPSO vessels is analyzed. We present the results of a comparison of power-to-volume ratio, power-to-weight ratio and efficiency for diesel and gas turbine power modules of various capacities. Mathematical modeling methods are used to analyze the parameters of an alternative gas turbine unit based on steam conversion of the associated gas, and the estimated efficiency of the energy module is shown to be 50%. In the modeling of the burning processes, the UGT 25000 serial low emission combustor is considered, and a detailed analysis of the processes in the combustor is presented, based on the application of a 35-reaction chemical mechanism. We confirm the possibility of efficient combustion of associated gas steam conversion products with different compositions, and establish that stable operation of the gas turbine combustor is possible when using fuels with low calorific values in the range 7–8 MJ/kg. It is found that the emissions of NOx and CO during operation of a gas turbine engine on the associated gas conversion products are within acceptable limits.
10
Sengupta, Sobhan, and John O'R Breeden. "A Method for “Punch-Through” Proof Design for Independent Leg Jack-Ups." Marine Technology and SNAME News 22, no. 01 (January 1, 1985): 50–63. http://dx.doi.org/10.5957/mt1.1985.22.1.50.
Full textAbstract:
"Punch-through" is one of the most common types of failure affecting independent leg self-elevating-type mobile offshore drilling units (jack-ups), and existing rules do not provide any guidelines to design for "punch-through" induced forces. This paper presents a systematic method for analysis and design of independent leg jack-ups for such forces, identifying the important design and operating parameters and evaluating their effects. The method can be used to design the jack-up legs for a given set of operating parameters, or for an existing unit it can be used to define the limiting values of these parameters. Based on these limitations, operating procedures can be developed to eliminate or minimize the chances of leg damage due to punch-through. A realistic example is worked out to demonstrate the application of the method.
11
Lee, Hyewon, Myung-Il Roh, Seung-Ho Ham, and Sol Ha. "Dynamic simulation of the wireline riser tensioner system for a mobile offshore drilling unit based on multibody system dynamics." Ocean Engineering 106 (September 2015): 485–95. http://dx.doi.org/10.1016/j.oceaneng.2015.07.028.
Full text
12
Kim, Yongho, and Kwangkook Lee. "Pressure Loss Optimization to Reduce Pipeline Clogging in Bulk Transfer System of Offshore Drilling Rig." Applied Sciences 10, no. 21 (October 26, 2020): 7515. http://dx.doi.org/10.3390/app10217515.
Full textAbstract:
In offshore drilling systems, the equipment localization rate is less than 20%, and the monopoly of a few foreign conglomerates over the equipment is intensifying. To break this monopoly, active technology development and market entry strategies are required. In a drillship or a floating production, storage, and offloading unit, the distance from the tank top to the upper deck is approximately 30–40 m. Therefore, the pressure loss problem inside the vertical pipe from the tank to the deck should be considered. To transport the bulk at the target transport rate without clogging, the pressure loss inside the vertical pipe should be optimized. Moreover, the operating pressure, air volume, and transport rate accuracy determine the system and operating costs. Hence, system optimization is necessary. In this study, pressure loss modeling and simulation of the bulk transfer system are performed to prevent frequent pipeline clogging. The proposed simulation model is verified using real test data. The bulk transfer system is verified through a simulation, indicating an error rate of 4.27%. In addition, the number of air boosters required to minimize the pipeline’s pressure loss and the optimal distance between the boosters are obtained using a genetic algorithm. With the optimized air booster, pressure loss for approximately 0.54 bar was compensated. The improved bulk transfer system is expected to reduce uncertainty and minimize maintenance and repair costs during operation. Moreover, it can contribute to high-value fields such as construction, commissioning, installation, maintenance, and equipment localization improvement.
13
Wang, Jian, Xu Liu, Wen Li, Fei Liu, and Craig Hancock. "Time–Frequency Extraction Model Based on Variational Mode Decomposition and Hilbert–Huang Transform for Offshore Oil Platforms Using MIMU Data." Symmetry 13, no. 8 (August 6, 2021): 1443. http://dx.doi.org/10.3390/sym13081443.
Full textAbstract:
Time–frequency extraction is a key issue to understand structural symmetry of dynamic responses of offshore oil platforms for early warning during drilling operations. Current popular methods for signal characteristics extraction can only obtain the attributes with a single dimension or poor precision. To solve this, a combined Hilbert–Huang transform (HHT) and variational mode decomposition (VMD) method is proposed to extract multidimensional dynamic response characteristics of time, frequency, and energy of offshore oil platforms. Based on the extracted time–frequency–energy information, the frequency-domain integration approach (FDIA) can be applied to calculate the displacement using accelerometer in the micro inertial measurement unit (MIMU). A complementary filtering algorithm was designed to measure the torsion angle of platforms using six degrees of freedom data from the MIMU to obtain the torsion angle information. The performance of the proposed method was validated using a series of simulation shaking-table tests and a field test conducted on an offshore oil platform at Dongying City, Shandong Province, China. During the field test, seven out of eight collisions were detected in the frequency range 5 Hz to 12 Hz. The intensity of the fifth collision was the highest, and the maximum displacement obtained by the accelerometer was 6 mm. In addition, the results show a correlation between the axes of the accelerometer and gyroscope, and their combination can measure a torsion angle up to 1.1°.
14
Sullivan, Paul. "A risk management approach to safe mooring systems in Australia." APPEA Journal 56, no. 2 (2016): 550. http://dx.doi.org/10.1071/aj15056.
Full textAbstract:
In March 2015, during cyclone Olwyn, a mobile offshore drilling unit (MODU) experienced a mooring failure and loss of position event. The MODU was blown some three nautical miles off location in the vicinity of subsea and surface infrastructure. There are serious safety, environmental, financial, and reputational risks that can be presented by a loss of mooring position. In response, NOPSEMA hosted a workshop with members of APPEA, the International Drilling Contractors Association (IADC) and with mooring contractors with a view to collectively improve the management of risks associated with the mooring of MODUs in Australia’s tropical waters, both in the short and longer term. Following this workshop, NOPSEMA issued an Information Note for the 2015/16 cyclone season, describing the regulators’ expectations of industry duty holders in respect of MODU mooring system management. At the same time, APPEA’s Drilling Industry Steering Committee (DISC) members aligned on the key principles underpinning a MODU mooring system approach. In late 2015, the APPEA DISC members commissioned a working group to develop a guidance framework for MODU mooring management in Australian tropical waters. DISC aims to work closely with industry partners such as IADC and specialist mooring contractors in the development of this framework. DISC has tasked the working group to have the guidance framework ready for the 2016/17 cyclone season, and for presentation at the 2016 APPEA Conference. The completed case study, presented at the APPEA Conference, provides an excellent example of a goal-setting and continuous improvement regulatory regime working as designed and intended.
15
JPT staff, _. "E&P Notes (August 2021)." Journal of Petroleum Technology 73, no. 08 (August 1, 2021): 15–17. http://dx.doi.org/10.2118/0821-0015-jpt.
Full textAbstract:
Energean Secures Rig for Multiwell Program off Israel Energean has signed a contract with Stena Drilling for an up to five-well drilling program offshore Israel, which is expected to target the derisking of unrisked prospective recoverable resources of more than 1 billion BOE. The contract is for the drilling of three firm wells and two optional wells using drillship Stena Icemax. The first firm well is expected to spud in early 2022. The firm wells are all expected to be drilled during 2022. “Our five-well growth program off-shore Israel, commencing in the first quarter of 2022, has the potential to double Energean reserve base with resource volumes that can be quickly, economically, and safely monetized,” said Mathios Rigas, chief executive of Energean. “Combined with first gas from our flagship Karish gas development project in mid-2022, the next 12 months are set to be truly transformational for Energean.” One of the firm wells is the Karish North development well. The scope includes re-entry, sidetracking, and completion of the previously drilled Karish North well and completion as a producer. The Karish North development will commercialize 1.2 Tcf of natural gas plus 31 million bbl of liquids and is expected to deliver first gas during the first half of 2023. The program also includes the Karish Main-04 appraisal well and the Athena exploration well, located in Block 12, directly between the Karish and Tanin leases. Athena is estimated to contain unrisked recoverable prospective resource volumes of 0.7 Tcf of gas plus 4 million bbl of liquids. Exxon Hits, Misses off Guyana ExxonMobil made another new discovery in the Stabroek Block offshore Guyana but came away empty with a well on the Canje block. The Longtail-3 well on the Stabroek block struck 230 ft of net pay, including newly identified reservoirs below those intervals found in the Longtail-1 probe. “Longtail-3, combined with our recent discovery at Uaru-2, has the potential to increase our resource estimate within the Stabroek block, demonstrating further growth of this world-class resource and our high-potential development opportunities offshore Guyana,” said Mike Cousins, senior vice president of exploration and new ventures at ExxonMobil. Exxon operates the 6.6-million-acre Stabroek Block as part of a consortium that includes Hess and China’s CNOOC. The new well was drilled 2 miles south of Longtail-1, which was drilled in 2018 and encountered 256 ft of oil-bearing sandstone. The Uaru-2 well in the Stabroek Block was announced in April. That well struck 120 ft of pay. While Stabroek drilling success continues, the operator suffered a set-back on the nearby Canje block and its Jabillo-1 well. The Stena Carron drillship reached a planned target depth of 6475 m; however the well failed to encounter commercial hydrocarbons. According to partner Eco Oil and Gas, the well was drilled to test Upper Cretaceous reservoirs in a stratigraphic trap. Drillship Stena Drillmax will next mobilize to drill the Sapote-1 prospect located in the south-eastern section of Canje, in a separate and distinct target from Jabillo. Sapote-1 lies approximately 100 km southeast of Jabillo and approximately 50 km north of the Haimara discovery in the Stabroek Block, which encountered 207 ft of gas-condensate-bearing sandstone reservoir. Erdogan Touts Turkish Black Sea Natural Gas Discoveries Turkey President Recep Tayyip Erdogan announced the discovery of new natural gas deposits in the Black Sea, where the country plans to start production in 2023. State energy company Tpao found 135 Bcm of gas at the Amasra-1 off-shore well, bringing the total amount of deposits discovered over the past year to 540 Bcm, according to Erdogan. Turkey has ramped up offshore exploration for hydrocarbons over the past few years. Last year, explorers found 405 Bcm of gas at the Tuna-1 well in Sakarya field. Turkey currently imports nearly all the 50 Bcm of gas it consumes annually. Equinor Hits Oil Near Visund Equinor struck oil in Production License 554 with a pair of wells at its Garantiana West prospect. Exploration wells 34/6-5 S and 34/6-5 ST2 were drilled some 10 km north-east of the Visund field, with the former encountering a total oil column of 86 m in the Cook formation. The latter well encountered sandstones in the Nansen formation, but did not encounter commercial hydro-carbons. Recoverable resources are esti-mated at between 8 and 23 million BOE. “This is the first Equinor-operated well in the production license, and the fifth discovery on the Norwegian continental shelf this year,” said Rune Nedregaard, senior vice president, exploration and production south. “The discovery is in line with our roadmap of exploring near existing infrastructure in order to increase the commerciality.” Well 34/6-5 S was drilled using Seadrill semisubmersible rig West Hercules. Equinor operates the discovery; partners include Var Energi and Aker BP. ExxonMobil Eyes Flemish Pass Well ExxonMobil is looking to secure a semi-submersible to complete the drilling of a deepwater wildcat in the Flemish Pass offshore eastern Canada. The operator began drilling the Hampden K-41 probe in the spring of last year using Seadrill semisubmersible rig West Aquarius, but the unit was pulled off the well soon thereafter for reasons unknown. ExxonMobil is currently prequalifying companies to supply a mobile offshore drilling unit to continue the well at Hampden in Exploration License (EL) 1165A. The operator is targeting a mid-year 2022 start to the probe to be drilled in around 1175 m of water, some 454 km from St. John’s, Newfoundland. Meanwhile, China’s CNOCC has wrapped up drilling on its Pelles prospect, its first exploration well offshore Newfoundland. The prospect, in about 1163 m of water, is located within license EL 1144. The wildcat was originally set to spud in early 2020 but was delayed due to impacts of the COVID-19 pandemic. The company confirmed that drilling operations onboard drillship Stena Forth were complete and the rig plugged and abandoned the well. The results of the well were not released. Equinor To Drop Mexican Offshore Leases Equinor will exit two Mexican deepwater blocks as part its upstream investment strategy to focus on assets offering rapid and strong returns. The two blocks located in the Salina Sureste basin were acquired in Mexico’s 1.4 bid round in an equal equity split with BP and TotalEnergies. Block 3, where Equinor holds a 33% operating interest, has water depths ranging from 900 to 2500 m. Block 1, where BP is the operator, has water depths ranging from 200 to 3100 m. Exploration commitments include a single well on each block, not yet drilled. The announcement to exit Mexico was made by Executive Vice President for E&P International Al Cook during the company’s Capital Markets Day event held in June. The company also unveiled plans to leave Nicaragua and Australia, as part of its upstream investment plans. Cook added that Equinor will only operate offshore assets moving forward and will no longer operate onshore, unconventional projects. The company will instead opt to partner with others on those projects. Equinor will also look to offload its exploration assets in the Austin Chalk play in the US and Terra Nova in Canada, he said. Var Energi Strikes North Sea Oil Var Energi has confirmed a discovery at its King and Prince exploration wells in the Balder area in the Southern North Sea. Success at the combined King and Prince exploration wells lifts preliminary estimates of recoverable oil equivalents between 60 and 135 million bbl. King/Prince was drilled in PL 027 by semisubmersible rig Scarabeo 8. The Prince well encountered an oil column of about 35 m in the Triassic Skagerrak formation within good to moderate reservoir sandstones, while the King well discovered a gas column of about 30 m and a light oil column of about 55 m with some thick Paleogene sandstone. An additional King appraisal side-track further confirmed a 40-m gas column and an oil column of about 55 m of which about 35 m are formed by thick and massive oil-bearing sandstone with excellent reservoir quality. The licensees consider the discoveries to be commercial and will assess tie-in to the existing infrastructure in the Balder area. The wells are located about 6 km north of the Balder field and 3 km west of the Ringhorne platform. Var Energi operates and holds a 90% stake of the license. Mime Petroleum holds the remaining 10%.
16
Sheil, Henry, Peter Young, and Martin Richardson. "Cost reduction of subsea gas production systems using emerging hydrate remediation technology." APPEA Journal 51, no. 1 (2011): 201. http://dx.doi.org/10.1071/aj10014.
Full textAbstract:
Gas flowlines are presenting flow assurance challenges in hydrate management resulting from low ambient seawater temperatures in an increasing number of deepwater developments. When the equilibrium hydrate temperature of the produced fluid is above the minimum seabed temperature, and the hydrate inhibition system fails, there is a risk of hydrate blockage in the subsea system. The industry-preferred approach for hydrate blockage remediation is dual sided depressurisation (DSD). The objective is to depressurise the flowline below hydrate onset conditions, thus allowing hydrate dissociation and safe disposal of the gas inventory. This is generally performed by one of two methods: installation of a dual flowline system for facility-based depressurisation (CAPEX impact) or by connecting a mobile offshore drilling unit (MODU) to an appropriate wellhead or christmas tree (XT) to allow simultaneous depressurisation at the MODU and the facility (OPEX impact). It is recognised that both methods incur significant costs. Typically the cost, schedule and availability uncertainties of bringing in a MODU to solve these production stoppages are too high. Consequently, subsea developments often select the increased CAPEX option. An optimisation of the MODU-based intervention method is the subject of this paper. The feasibility of using a lightweight intervention vessel (e.g. an offshore support vessel) in place of the MODU is investigated. In discussing this optimisation, this paper also presents an introduction to hydrate remediation theory, some practical challenges, case studies and vessel requirements.
17
Conway, A. M., and C. Valvatne. "The Boulton Field, Block 44/21a, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 671–80. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.53.
Full textAbstract:
AbstractThe Boulton Field was discovered in 1984 when gas was tested from the Lower Ketch Unit, Carboniferous Westphalian C/D, in well 44/21-2. Following appraisal drilling in 1990, the Boulton 'B' structure was delineated and a trap confirmed by a combination of up-dip seal against basal Permian shales, and salts and lateral seal against sealing faults and impermeable Westphalian C sediments. A second structure was drilled in the same year, Boulton 'F', with gas discovered in the deeper Murdoch Sand Interval of the Westphalian C/D. The two separate structures collectively form the Boulton Field.Current deliverability from the 'B' structure, Lower Ketch Sands is approximately 100 MMSCFD from a single producer. Developed with a minimal platform facility, the gas is delivered to Theddlethorpe Gas Terminal via offshore compression at the nearby Murdoch Field. The reservoir in Boulton 'B' comprises a series of channel sands deposited in a braided stream complex flowing predominantly from north to south across an Upper Carboniferous alluvial plain. Sandbody connectivity within the complex fluvial architecture of the Westphalian C is a key control on gas production.
18
Liu, Xiangbo, Allan Ross Magee, Aziz Merchant, Anis Hussain, Ankit Choudhary, Amit Jain, and Bernad A. P. Francis. "A Parametric Study on the Innovative Coupling Arm Connecting the Coupled TAD-TLP." MATEC Web of Conferences 203 (2018): 01017. http://dx.doi.org/10.1051/matecconf/201820301017.
Full textAbstract:
Two body marine systems, like a Tender Assisted Drilling (TAD) vessel coupled with a floating Dry-Tree Unit (DTU), have become very common in offshore operations. One of the unavoidable challenge we have to cope with is the connection between the TAD and DTU should make sure the TAD does not drift away from the platform and also avoid the possible collision in case of a harsher environment. The objective of this study is to understand the hydrodynamic interactions between the two coupled floating bodies and improve the devising of the innovative connection system. In this study, an innovative rigid connection system, the coupling arm is applied to connect the TAD and a DTU, in this case, a Tension Leg Platform (TLP). The whole system is modelled by the commercial software HARP. A comprehensive parametric study on the pretension and the nominal length of the coupling arm is carried out. The hydrodynamic analysis of the coupled TAD-TLP system elucidates the interactions between the two bodies. The chosen combination of the coupling arm pretension and the nominal length will determine the required stroke range and maximum forces needed to design the innovative coupling arm for safe operations.
19
Jacobs, Trent. "Mud-Gas Breakthrough Equinor Develops Real-Time Reservoir-Fluid Identification." Journal of Petroleum Technology 73, no. 02 (February 1, 2021): 37–39. http://dx.doi.org/10.2118/0221-0037-jpt.
Full textAbstract:
For all that logging-while-drilling has provided since its wide-spread adoption in the 1980s, there is one thing on the industry’s wish list that it could never offer: an accurate way to tell the difference between oil and gas. A new technology created by petrotechnicals at Equinor, however, has made this possible. The innovation could be thought of as a pseudo-log, but Equinor is describing it as a reservoir-fluid-identification system. Using an internally developed machine-learning model, it compares a database of more than 4,000 reservoir samples against the real-time analysis of the mud gas that flows up a well as it is drilled. Crunched out of the technology’s various hardware and software components is a prediction on the gas/oil ratio (GOR) that the rock being drilled through will have once it is producing. Since this happens in real time, it boils down to an alert system for when drillers are tapping into uneconomic pay zones. “This is something people have tried to do for 30 years - using partial information to predict entire oil and gas properties,” said Tao Yang. He added that “the data acquisition is rather cheap compared with all the downhole tools, and it doesn’t cost you rig time,” highlighting that the mud-gas analyzer critical to the process sits on a rig or platform without interfering with drilling operations. Yang is a reservoir technology specialist at Equinor and one of the authors of a technical paper (SPE 201323) about the new digital technology that was presented at the SPE Annual Technical Conference and Exhibition in October. He and his colleagues spent more than 3 years building the system which began in the Norwegian oil company’s Houston office as a project to improve pressure/volume/temperature (PVT) analysis in tight-oil wells in North America. It has since found a home in the company’s much larger offshore business unit in Stavanger. Offshore projects designed around certain oil-production targets can face harsh realities when they end up producing more associated gas than expected. It is the difference between drilling an underperforming well full of headaches and one that will pay out hundreds of millions of dollars over its lifetime. By introducing real-time fluid identification, Equinor is trying to enforce a new control on that risk by giving drillers the information they need to pull the bit back and start drilling a side-track deeper into the formation where the odds are better of finding higher proportions of oil or condensates. At the conference, Yang shared details about some of the first field implementations, saying that in most cases the GOR predictions made by the fluid-identification system were confirmed by traditional PVT analysis from the trial wells. Unlike other advancements made on this front, he also said the new approach is the first of its kind to combine such a large database of PVT data with a machine-learning model “that is common to any well.” That means “we do not need to know where this well is located” to make a GOR prediction, said Yang.
20
Singh, Amrita, Maheswar Ojha, and Kalachand Sain. "Predicting lithology using neural networks from downhole data of a gas hydrate reservoir in the Krishna–Godavari basin, eastern Indian offshore." Geophysical Journal International 220, no. 3 (December 30, 2019): 1813–37. http://dx.doi.org/10.1093/gji/ggz522.
Full textAbstract:
SUMMARY We use the unsupervised and supervised neural network methods together to predict lithology of a gas hydrate reservoir from downhole data in the Krishna–Godavari (KG) offshore basin, India. In this study, we successfully identify the host litho-units of gas hydrate and show its effects in the identification of lithology using neural network techniques, which is not reported earlier. We use well log data acquired at three holes (10A, 03A and 04A) in 2006 during the first expedition of the Indian National Gas Hydrate Program (NGHP-01). Five different logging while drilling data (e.g. density, neutron porosity, gamma ray, resistivity and sonic) are considered for the mapping of lithology and gas hydrate. In the presence of gas hydrate, the resistivity and sonic velocity of the host sediments increase significantly, whereas density, neutron porosity and gamma ray are negligibly affected. Therefore, we calculate resistivity and sonic velocity for water-saturated sediment (without gas hydrate) theoretically to remove the effects of gas hydrate. At first, we apply the seven unsupervised classification methods (i.e. elbow, dendrogram, K-means, 3-D clustering, principal component analysis, Devies–Bouldin index and self-organizing map) to the data with gas hydrate (e.g. observed) and without gas hydrate (i.e. water-saturated/theoretical) to assess the data dimensionality and the number of clusters/litho-units. Each of the unsupervised schemes has its own pros and cons, and may provide different number of cluster/litho-units; sometimes, it is difficult to interpret from only one method. However, all seven methods provide same number of clusters in our study. Then, we apply the supervised classification method (i.e. Bayesian neural networks optimized by hybrid Monte Carlo searching technique) to the training data to refine the defined litho-units and map them with depth. Our approach identifies four types of litho-units and illustrates that the lithology in this area is dominated by clay (∼64 per cent) with some amount of silty clay, silt and minor sand. Gas hydrate is found in clay, silty clay and silt and not in sand. Results also show that, if gas hydrate is not considered as a separate unit, it is distributed as lithology in its hosts (i.e. clay, silty clay and silt). The method is very stable up to ∼15 per cent of random noise added to the data and results are well matched with the analysis of recovered core data. Identified lithologies at three wells correlate very well with seismic section crossing the wells. Very low permeability (<0.1 mD) estimated at three wells also indicates the clay-dominated lithology in our study area.
21
Jang, Junbong, William F. Waite, and Laura A. Stern. "Gas hydrate petroleum systems: What constitutes the “seal”?" Interpretation 8, no. 2 (May 1, 2020): T231—T248. http://dx.doi.org/10.1190/int-2019-0026.1.
Full textAbstract:
The gas hydrate petroleum system (GHPS) approach, which has been used to characterize gas hydrates in nature, uses three distinct components: a methane source, a methane migration pathway, and a reservoir that not only contains gas hydrate, but also acts as a seal to prevent methane loss. Unlike GHPS, a traditional petroleum system (PS) approach further distinguishes between the reservoir, a unit with generally coarser sediment grains, and a separate overlying seal unit with generally finer sediment grains. Adopting this traditional PS distinction in the GHPS approach facilitates assessments of reservoir growth and production potential. The significance of the seal for the formation of a gas hydrate reservoir as well as for efficiency in methane extraction from the reservoir as an energy resource is evident in findings from recent offshore field expeditions, such as India’s second National Gas Hydrate Program expedition (NGHP-02). In regard to gas hydrate-bearing reservoir formations, the NGHP-02 gas chemistry data indicate a primarily microbial methane source. Fine-grained seal sediment in contact with coarser grained reservoir sediment can facilitate that microbial methane production. Logging-while-drilling and sediment core data also indicate that the overlying fine-grained seal sediment is less permeable than the underlying, highly gas hydrate-saturated reservoir sediment. The overlying seal’s capacity to act as a low-permeability boundary is important not only for preventing methane migration out of the reservoir over time, but also for preventing water invasion into the reservoir during methane extraction from the reservoir. Ultimately, the presence of an overlying, fine-grained, low-permeability “seal” influences how gas hydrate initially forms in a coarse-grained reservoir and dictates how efficiently methane can be extracted as an energy resource from the gas hydrate reservoir via depressurization.
22
Miller, Jessica, and Nick Quinn. "EXERCISE WESTWIND – A COLLABORATIVE OIL SPILL RESPONSE BY OIL & GAS OPERATORS AND AGENCIES." International Oil Spill Conference Proceedings 2017, no. 1 (May 1, 2017): 2851–62. http://dx.doi.org/10.7901/2169-3358-2017.1.2851.
Full textAbstract:
Abstract On June 9th, 2015, ACME Oil Company’s rig suffered a dynamic positioned ‘run-off’. The mobile drilling unit lost its station above the wellhead and a loss of well control was experienced. “A massive environmental emergency unfolded…affecting pristine coastline and masses of wildlife”. Incident Management and Field Response Teams were activated in a multi-agency operation, bringing together 200 personnel from 16 oil and gas companies and 18 government agencies and third party providers. Source control, aerial, offshore, nearshore, shoreline and oiled wildlife response capabilities were deployed and national/international support was utilised. Jointly managed by the Australian Marine Oil Spill Centre (AMOSC), the Australian Maritime Safety Authority (AMSA), the Federal Department of Industry and Science, and the Western Australian Department of Transport -Exercise Westwind was a successful multi-faceted marine spill response, demonstrating Australia’s collective Industry/Government capacity to respond to a large, offshore loss of well control incident in a remote and isolated location. ACME Oil Company was a fictitious company formed to enable the amalgamation of Australian petroleum companies to exercise industry arrangements under one ‘banner’ during the exercise period. ACME Oil Company had its own set of credentials, company website and Oil Pollution Emergency Plan. The company also held real time memberships with a number of service providers including AMOSC, Oil Spill Response Ltd, Trendsetter Engineering International, Oceaneering Australia and addenergy. Representing an innovative approach to spill response exercising, ACME Oil Company was a valuable and critical aspect to industry and governments participation under a non-attributable banner. Additionally, it enabled safe, widespread lessons to be observed, allowed for real-time testing of arrangements and provided a safe environment for regulators, stakeholder and industry interplay. The exercise was an efficient and practical solution for Industry titleholders and their third party supporting organisations, to test shared response resources and to ensure Industry arrangements for responding to oil pollution are in accordance with the Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009. This paper will discuss the development program behind the exercise and the experience of managing an exercise of this nature. It will highlight the successes including the creation and implementation of a fictitious company and the extensive collaboration between the industry and government personnel involved. It will also look forward – where are we 11-months later? Can the history of exercising and/or response help us improve for the future-implementation of change and continued testing is critical in furthering our oil spill response capability and capacity.Exercise Westwind – Operational Phase TwoExercise Westwind – Operational Phase Two
23
Hussein, Marwa, Robert R. Stewart, Deborah Sacrey, Jonny Wu, and Rajas Athale. "Unsupervised machine learning using 3D seismic data applied to reservoir evaluation and rock type identification." Interpretation 9, no. 2 (April 21, 2021): T549—T568. http://dx.doi.org/10.1190/int-2020-0108.1.
Full textAbstract:
Net reservoir discrimination and rock type identification play vital roles in determining reservoir quality, distribution, and identification of stratigraphic baffles for optimizing drilling plans and economic petroleum recovery. Although it is challenging to discriminate small changes in reservoir properties or identify thin stratigraphic barriers below seismic resolution from conventional seismic amplitude data, we have found that seismic attributes aid in defining the reservoir architecture, properties, and stratigraphic baffles. However, analyzing numerous individual attributes is a time-consuming process and may have limitations for revealing small petrophysical changes within a reservoir. Using the Maui 3D seismic data acquired in offshore Taranaki Basin, New Zealand, we generate typical instantaneous and spectral decomposition seismic attributes that are sensitive to lithologic variations and changes in reservoir properties. Using the most common petrophysical and rock typing classification methods, the rock quality and heterogeneity of the C1 Sand reservoir are studied for four wells located within the 3D seismic volume. We find that integrating the geologic content of a combination of eight spectral instantaneous attribute volumes using an unsupervised machine-learning algorithm (self-organizing maps [SOMs]) results in a classification volume that can highlight reservoir distribution and identify stratigraphic baffles by correlating the SOM clusters with discrete net reservoir and flow-unit logs. We find that SOM classification of natural clusters of multiattribute samples in the attribute space is sensitive to subtle changes within the reservoir’s petrophysical properties. We find that SOM clusters appear to be more sensitive to porosity variations compared with lithologic changes within the reservoir. Thus, this method helps us to understand reservoir quality and heterogeneity in addition to illuminating thin reservoirs and stratigraphic baffles.
24
Schiøler, Poul, Jan Andsbjerg, Ole R. Clausen, Gregers Dam, Karen Dybkjær, Lars Hamberg, Claus Heilmann-Clausen, Lars E. Kristensen, Iain Prince, and Jan A. Rasmussen. "A revised lithostratigraphy for the Palaeogene – lower Neogene of the Danish North Sea." Geological Survey of Denmark and Greenland (GEUS) Bulletin 7 (July 29, 2005): 21–24. http://dx.doi.org/10.34194/geusb.v7.4825.
Full textAbstract:
Intense drilling activity following the discovery of the Siri Field in 1995 has resulted in an improved understanding of the siliciclastic Palaeogene succession in the Danish North Sea sector (Fig. 1). Many of the new wells were drilled in the search for oil reservoirs in sand bodies of Paleocene–Eocene age. The existing lithostratigraphy was based on data from a generation of wells that were drilled with deeper stratigraphic targets, with little or no interest in the overlying Palaeogene sediments, and thus did not adequately consider the significance of the Palaeogene sandstone units in the Danish sector. In order to improve the understanding of the distribution, morphology and age of the Palaeogene sediments, in particular the economically important sandstone bodies, a detailed study of this succession in the Danish North Sea has recently been undertaken. An important aim of the project was to update the lithostratigraphic framework on the basis of the new data.The project was carried out at the Geological Survey of Denmark and Greenland (GEUS) with participants from the University of Aarhus, DONG E&P and Statoil Norway, and was supported by the Danish Energy Agency. Most scientific results cannot be released until September 2006, but a revised lithostratigraphic scheme may be published prior to that date. Formal definition of new units and revision of the lithostratigraphy are in preparation. All of the widespread Palaeogene mudstone units in the North Sea have previously been formally established in Norwegian or British wells, and no reference sections exist in the Danish sector. As the lithology of a stratigraphic unit may vary slightly from one area to another, Danish reference wells have been identified during the present project, and the lithological descriptions of the formations have been expanded to include the appearance of the units in the Danish sector. Many of the sandstone bodies recently discovered in the Danish sector have a limited spatial distribution and were sourced from other areas than their contemporaneous counterparts in the Norwegian and British sectors. These sandstone bodies are therefore defined as new lithostratigraphic units in the Danish sector, and are assigned Danish type and reference sections. There is a high degree of lithological similarity between the Palaeogene–Neogene mudstone succession from Danish offshore boreholes and that from onshore exposures and boreholes, and some of the mudstone units indeed seem identical. However, in order to acknowledge the traditional distinction between offshore and onshore stratigraphic nomenclature, the two sets of nomenclature are kept separate herein. In recent years oil companies operating in the North Sea have developed various in-house lithostratigraphic charts for the Paleocene–Eocene sand and mudstone successions in the Danish and Norwegian sectors. A number of informal lithostratigraphic units have been adopted and widely used. In the present project, these units have been formally defined and described, maintaining their original names whenever feasible, with the aim of providing an unequivocal nomenclature for the Palaeogene – lower Neogene succession in the Danish sector. It has not been the intention to establish a sequence stratigraphic model for this succession in the North Sea; the reader is referred to the comprehensive works of Michelsen (1993), Neal et al. (1994), Mudge & Bujak (1994, 1996a, b), Michelsen et al. (1995, 1998), Danielsen et al. (1997) and Rasmussen (2004).
25
van Kessel, Onno. "Champion East: Low-Cost Redevelopment of Shallow, Stacked, and Faulted Heavy-Oil Reservoirs." SPE Reservoir Evaluation & Engineering 5, no. 04 (August 1, 2002): 295–301. http://dx.doi.org/10.2118/78674-pa.
Full textAbstract:
Summary The Champion East area offshore Brunei Darussalam consists of approximately 50 stacked, shallow, and intensely faulted heavy oil reservoirs. These reservoirs have been under development since 1975 and have to date produced just 9% of the oil initially in place. Over the period 1998-2003, Brunei Shell Petroleum (BSP) is embarking on a major redevelopment with the aim of converting a further 30 million m3 of oil-in-place volume into commercial reserves. An overview will be given of how new technology is adding value to the total redevelopment, supported by actual application results and learning points. The primary development of Champion East is now nearing completion. The use of existing facilities and ultra shallow, long reach horizontal wells - with innovative sand exclusion and downhole intelligence - has achieved a 60% unit cost reduction over previous drilling campaigns in the area. The only way to unlock another 5 to 15% of the oil-in-place volume is to start secondary recovery through water injection, in combination with the use of electric submersible pumps (ESPs). Introduction The Champion Asset comprises the Champion Field offshore Brunei Darussalam (Fig. 1) and all associated facilities and infrastructure, which also serve as an export hub for BSP's entire Offshore East production division. Oil production from the Champion Field averages approximately one-third of total BSP production. A large scope for recovery, mostly technology-driven, remains, even at low oil prices. Subsurface, the area comprises a hydrostatic, heterolithic sequence of interbedded thin sandstones and mudstones (with reservoir flow units no more than 15 m thick and permeabilities ranging from 0.01 to 0.2 µm2 in lower shoreface sands to 0.5 to 5 µm2 in tidal channels) deposited in environments spanning a systems tract that extends from the outer shelf into the lower coastal plain. Other key features are significant lateral thickness variations, compartmentalization caused by syndepositional tectonics, and the presence of multiple growth faults. The Champion field can be divided into two distinct parts (Fig. 2): Champion East, spanning a depth of approximately 200 to 1200 m, with hydrocarbons in some places seeping through the seabed and feeding a coral reef; and Champion Main, which encompasses a depth of approximately 1000 to 2000 m. Champion Main contains the mature core of the Champion field, where both primary and secondary (water-injection) recovery processes are well advanced and 28% of the oil initially in place has been produced. The main focus in Champion Main is on water-injection maintenance, production-system optimization, and scope for recompleting or sidetracking existing wells-all aimed at slowing the decline in oil production. Most efforts in the area are, however, focused on the growth potential offered by shallow reservoirs. The Champion East area is much less mature than Champion Main, with a cumulative oil production to date of just 9% of the oil initially in place. Historically, Champion East is underdeveloped because of its subsurface complexity and heterogeneity (leading to erratic well performance), less favorable reservoir and oil properties [density of 930 g/cm3 (20° API) and viscosity between 5 and 15 mPa's], and a perceived lack of spare conductor slots, which would necessitate large investments in new infrastructure. In 1995, it was estimated that an upfront investment in excess of U.S. $400 million would be required to advance the development of Champion East by accessing another 30 million m3 of undeveloped reserves. Out of this total, 40% would be required for new facilities, and the remaining 60% would be for drilling new wells. This hurdle essentially halted further developments (between 1992 and 1997, just one well was drilled in the area), and it was obvious that major changes were required to all the fundamentals (average reserves and rates per well, well costs, and facilities costs) to break this deadlock. The case for change, together with plans for possible solutions, is further described in Ref. 1. Reservoir Modeling Technology Traditionally, Champion East had been modeled with 2D methods of mapping gross interval properties for groups of reservoirs ranging in thickness from 20 to 40 m, using the previous 3D seismic survey shot in 1983 (relatively poor resolution) and well correlation methods based on lithostratigraphy. However, these methods often can prove unreliable in deltaic reservoirs that have undergone synsedimentary tectonics. The previous major Champion East infill drilling campaign (1990-92) was relatively unsuccessful because approximately 35% of all target reservoirs were found to be either nonexistent, water-bearing, or depleted. It then became clear that it was necessary to understand the structure, sequence stratigraphy, and fluid distribution of these reservoirs in greater detail. Two key data acquisition activities occurred in 1994: a high-resolution 3D seismic survey and the retrieval of some 350 m of continuous cores to review the sedimentology and high-resolution sequence stratigraphy, as described in Ref. 2. After screening studies to establish the correct priority and level of detail required, Shell's proprietary reservoir modeling software (GEOCAP-MoReS) was used to provide detailed 3D reservoir models for reservoir simulation. A total of 16 models were built and history matched (with approximately 50,000 grid cells each) between 1996 and 1999; together, they covered the entire area, with boundaries positioned (generally at sealing faults) to minimize crossflow effects. This allowed fast optimization of reservoir development plans by identifying connected oil in place and transmissibility for individual reservoir flow units, such as an upper shoreface sandbody or a tidal channel, which have remained undrained from previous development.
26
JPT staff, _. "E&P Notes (July 2021)." Journal of Petroleum Technology 73, no. 07 (July 1, 2021): 13–17. http://dx.doi.org/10.2118/0721-0013-jpt.
Full textAbstract:
Maha Appraisal Hits Gas for Eni in Indonesia Eni encountered natural-gas-bearing sands with its Maha 2 well in the West Ganal Block offshore Indonesia. Drilled to a depth of 2970 m in 1115 m water depth, the well encountered 43 m of gas-bearing net sands in levels of Pliocene Age, according to the operator. A production test, which was limited by surface facilities, recorded a gas deliverability of the reservoir flowing at 34 MMscf/D. The opera-tor collected data and samples during the test, to study in preparation of a field development plan for the Maha field. Two additional appraisal wells are planned for the discovery. Eni, along with partners Neptune West Ganal BV and P.T. Pertamina Hulu West Ganal, expect the field to be developed subsea and tied back to the nearby Jangkrik floating production unit (FPU), about 16 km to the northwest. Eni has been operating off Indonesia since 2001. Its current equity production in the region is around 80,000 BOE/D. Shell Sells Out of Philippines Gas Field Royal Dutch Shell has agreed to sell its stake in the Malampaya offshore gas field in the Philippines for $460 million. The major sold its 45% stake in Service Contract 38 (SC38), a deepwater license which includes the producing gas field, to a subsidiary of the Udenna Group, which already holds a 45% stake in the project. The divestment is part of the company’s strategy to narrow its oil and gas operations. The base consideration for the sale is $380 million, with additional payments of up to $80 million in 2022 and 2024 contingent on asset performance and commodity prices, according to Shell. The deal is due to complete by the end of 2021. The Malampaya gas field, discovered in 1991, currently supplies fuel to power plants that deliver about a fifth of the country’s electricity requirements, based on energy ministry data. Equinor Green Lights First Phase of Bacalhau Development Off Brazil Equinor, along with partners ExxonMobil, Petrogal Brasil, and Pré-Sal Petróleo SA, will move forward with a planned $8-billion Phase 1 development of the Bacalhau field in the Brazilian pre-salt Santos area. The Bacalhau field is situated across two licenses, BM-S-8 and Norte de Carcará. The target resource is a high-quality carbonate reservoir containing light oil. The development will consist of 19 subsea wells tied back to a floating production, storage, and offloading unit (FPSO) located at the field. The vessel will be one of the largest FPSOs in Brazil with a production capacity of 220,000 B/D of oil and 2 million bbl of storage capacity. The stabilized oil will be offloaded to shuttle tankers and the gas from Phase 1 will be re-injected in the reservoir. The FPSO contractor will operate the FPSO for the first year. Thereafter, Equinor plans to operate the facilities until the end of the license period. The development plan was approved by the Brazilian National Agency of Petroleum, Natural Gas, and Biofuels (ANP) in March 2021. First oil from the field is slated for 2024. Wintershall Strikes Gas at Dvalin North An exploration well drilled by Wintershall on its Dvalin North prospect in the Norwegian Sea has encountered a significant gas reservoir. The discovery at Dvalin North is estimated to hold to hold 33–70 million BOE and is just 12 km north of the company’s operated Dvalin field and 65 km north of the operated Maria field. The well also encountered hydrocarbons in two shallower secondary targets, with a combined resource estimate of 38–87 million BOE, making the potential for the field in excess of 150 million BOE. The well, drilled by the Deepsea Aberdeen rig, encountered gas, condensate, and oil columns of 33 m and 114 m in the Cretaceous Lysing and Lange formations, respectively. In the primary target in the Garn Formation, the well found a gas column of 85 m. The license partners, including Petoro and Sval Energi, are evaluating development options for the discovery, which could include a tieback to the Dvalin field. Third Odfjell Rig Tapped by Equinor Odfjell has been awarded a three-well, $40-million drilling contract for its semisubmersible drilling unit Deepsea Stavanger by Equinor. The rig will join sister units Deepsea Atlantic and Deepsea Aberdeen under contract with the Norwegian operator. The rig is scheduled to start drilling the first of three planned exploration wells in the North Sea in February 2022. The wells are expected to take about 4 months to complete. The contract includes continuing options after the initial phase. South Africa Shale Tests Encounter Gas at Karoo Pockets of shale gas were encountered during test drilling in the semi-desert Karoo region of South Africa, according to the nation’s energy ministry. A total of 34 gas samples had been bottled and taken to laboratories after the government’s Council for Geosciences set out to drill a 3500-m stratigraphic hole in the Karoo to establish and test the occurrence of shale gas. “The first pocket of gas was intercepted at 1734 m with a further substantial amount intercepted at 2467 m spanning a depth of 55 m,” said Gwede Mantashe, South African energy minister, during his budget vote in parliament on 18 May. In 2017, geologists at the University of Johannesburg and three other institutions estimated the gas resource in the Karoo was probably 13 Tcf. Earlier, the US Energy and Information Administration estimated the Karoo Basin’s technically recoverable shale-gas resource at 390 Tcf, then making it the eighth largest in the world and second largest in Africa behind Algeria. Seadrill Venture Nets New Drilling Contract Seadrill’s Sonadrill Holding Ltd., the 50/50 joint venture with an affiliate of Sonangol, has secured a 12-well contract with one option for nine wells and 11 one-well options in Angola for drillship Sonangol Quenguela. The $131-million contract before options is inclusive of mobilization revenue and additional services with commencement expected in early 2022 and running through mid-2023. The contract is contingent on National Concessionaire approval. Sonangol Quenguela is the second of two Sonangol-owned drillships to be bareboat-chartered into Sonadrill. The drillship is a seventh-generation, DP3, dual activity, e-smart ultradeepwater drillship delivered in 2019, capable of drilling up to 40,000-ft wells. A further two Seadrill-owned units are expected to be bareboat-chartered into Sonadrill. Seadrill will manage and operate the four units on behalf of Sonadrill. Shell Makes US Gulf Discovery at Leopard An exploration well at the Shell-led Leopard prospect in the deepwater US Gulf of Mexico encountered more than 600 ft net oil pay at multiple levels. Leopard is in Alaminos Canyon Block 691, approximately 20 miles east of the Whale discovery, 20 miles south of the recently appraised Blacktip discovery, and 33 miles from the Perdido spar host facility. Evaluation is ongoing to further define development options. According to Shell, Leopard is an opportunity to increase production in the Perdido Corridor, where its Great White, Silvertip, and Tobago fields are already producing. Meanwhile, the Whale discovery, also in the Perdido Corridor, is progressing toward a final investment decision in 2021. Shell operates Leopard with a 50% working interest. Partner Chevron holds the remaining 50% stake. Shell Could Leave Tunisia in 2022 Shell informed Tunisian authorities in May it will hand back upstream concessions and leave the country next year as it turns its focus to renewable energy, according to a Reuters report sourcing a senior official in the country’s energy ministry. The license in question is the Miskar concession in the southern city of Gabes. The operator has also requested the early hand-back of the Asdrubal permit, which expires in 2035. Recent reports suggest the operator may be looking for the Tunisian government to extend its permit on the field under more favorable terms ahead of its planned departure.
27
Springett, C. N., and M. W. Praught. "Semisubmersible Design Considerations—Some New Developments." Marine Technology and SNAME News 23, no. 01 (January 1, 1986): 12–22. http://dx.doi.org/10.5957/mt1.1986.23.1.12.
Full textAbstract:
This paper reviews the basic stability considerations applied in the design of semisubmersible drilling units. Rules and regulations governing the stability of mobile offshore drilling units (MODU's) were first introduced in the late 1960's. There has been considerable debate over the level of safety achieved in the present generation of MODU's based on existing rules. The assumptions implied in the early rules are discussed and the merits of a "yardstick" approach to the rules are presented. The paper summarizes the evolution of stability rules for mobile offshore drilling units and describes how the rules have changed due to public reaction to several major disasters.
28
Brkić, Dejan, and Zoran Stajić. "Offshore Oil and Gas Safety: Protection against Explosions." Journal of Marine Science and Engineering 9, no. 3 (March 16, 2021): 331. http://dx.doi.org/10.3390/jmse9030331.
Full textAbstract:
Offshore oil and gas operations carry a high risk of explosions, which can be efficiently prevented in many cases. The two most used approaches for prevention are: (1) the “International Electrotechnical Commission System for Certification to Standards Relating to Equipment for Use in Explosive Atmospheres” (IECEx) and (2) European “Atmosphere Explosible” (ATEX) schemes. The main shortcoming for the IECEx scheme is in the fact that it does not cover nonelectrical equipment, while for the ATEX scheme, it is due to the allowed self-certification for a certain category of equipment in areas with a low probability of explosions, as well as the fact that it explicitly excludes mobile offshore drilling units from its scope. An advantage of the IECEx scheme is that it is prescribed by the US Coast Guard for protection against explosions on foreign mobile offshore drilling units, which intend to work on the US continental shelf but have never operated there before, with an additional requirement that the certificates should be obtained through a US-based Certified Body (ExCB). Therefore, to avoid bureaucratic obstacles and to be allowed to operate with minimized additional costs both in the US and the EU/EEA’s offshore jurisdictions (and very possibly worldwide), all mobile offshore drilling units should be certified preferably as required by the US Coast Guard.
29
JPT staff, _. "E&P Notes (April 2021)." Journal of Petroleum Technology 73, no. 04 (April 1, 2021): 15–17. http://dx.doi.org/10.2118/0421-0015-jpt.
Full textAbstract:
Shell Selling Onshore Egypt Assets Shell Egypt and one of its affiliates have signed an agreement with a consortium made up of subsidiaries of Cheiron Petroleum Corporation and Cairn Energy PLC to sell its upstream assets in Egypt’s Western Desert for a base consideration of $646 million. Additional payments of up to $280 million between 2021 and 2024 will be made contingent on the oil price and the results of further exploration. The transaction is subject to government and regulatory approvals and is expected to complete in the second half of 2021. The package of assets comprises Shell Egypt’s interest in 13 onshore concessions and the company’s share in Badr El-Din Petroleum Company. Shell will shift its exploration focus in Egypt offshore, which includes seven new blocks in the Nile Delta, West Mediterranean, and Red Sea. Chevron Begins Production From Sarta-2 Well in Iraq Chevron has started production from the Sarta-2 well at the Sarta field in the Kurdistan region of Iraq, partner Genel Energy said. Gross field production now stands at more than 10,000 B/D. Sarta production is expected to increase from the existing two producing wells as facility optimization continues after production startup. A fresh appraisal drilling campaign is scheduled to begin soon, with the Sarta-5 and Sarta-6 wells set to be drilled back-to-back. Chevron is operator of the Sarta production-sharing contract (50%) with partners Genel Energy (30%) and the Kurdistan Regional Government (20%). Colombia Eyes Licensing Round Results in November Colombia is expected to soon reveal the schedule for its 2021 licensing round offering 32 blocks for oil and gas exploration, with results expected in November. In 2020, the nation awarded three areas to Canada-based companies Parex Resources and Canocol Energy despite the double-whammy of crashing crude demand and a global pandemic. With oil prices on the mend and an aggressive vaccine dissemination program, Colombia is hopeful that interest in its oil and gas acreage returns to pre-pandemic levels. The National Hydrocarbon Agency (ANH) expects to award at least half of the available tracts, which are part of more than 500 areas identified by the ANH in the country and include mature fields, emerging basins, and bordering areas. Exploration in Colombia fell dramatically in 2020 with only 18 wildcats drilled vs. the 45 planned, with most of the expected investment deferred to 2021-2022. While the country has allowed pilot projects testing for unconventional oil, there currently is a ban on fracking operations in the country. Israel Begins Prep Work for Fourth Offshore Round Israel’s Ministry of Energy has announced plans to launch the fourth offshore bidding round (OBR 4) for exploration licenses in the country’s exclusive economic zone soon. OBR 4 is part of a multiyear program to encourage the exploration and development of Israel’s natural resources to provide low-cost, environmentally friendly energy to Israel’s consumers and businesses and to develop markets for Israeli natural gas beyond its borders. As in OBR 2, the Ministry is planning to offer several zones to qualified companies, with each zone comprising approximately four licenses having a total area of up to 1600 sq km. Around 25 exploration licenses (blocks) have been mapped and will be grouped into six clusters. The exact dates of the stages of the bid round and grouping of the licenses in clusters will be determined later. No decision has yet been made on the winner of the license for natural gas and oil exploration in Block 72 in the third competitive bid round carried out in 2020. The Ministry will announce the formal commencement of OBR 4 and its delineation in the near future and provide detailed information on its website www.energy-sea.energy.gov.il at that time. Exxon Drills Dud at Bulletwood Offshore Guyana Exxon encountered noncommercial hydrocarbons with a test of its Bulletwood prospect in the Canje Block in the Guyana-Suriname basin. The well, located in 2846 m of water, was drilled to its planned target depth of 6690 m using drillship Stena Carron. Data collection from the Bulletwood-1 well confirms the presence of the Guyana-Suriname petroleum system and the potential prospectivity of the Canje Block, said partner Westmount Energy. Bulletwood-1 was the first of three scheduled wells to be drilled on the block in 2021. Wells Jabillo-1 and Sapote-1 are expected to spud over the coming months. Exxon operates the Canje Block via its Esso Exploration and Production Guyana unit, which has a 35% stake. Total has 35%, JHI 17.5%, and Mid-Atlantic Oil & Gas 12.5. Westmount holds a 7.7% stake in JHI. While the well results were disappointing, Exxon’s success rate in the area is still around 80% from 18 wells and expects its production from the region to reach 750,000 B/D by 2026. Neptune Earmarks $150 Million for Exploration and Appraisal in 2021 UK-based independent Neptune Energy said its exploration and appraisal spend for 2021 will remain flat at around $150 million. The company said it had up to 11 wells planned for the year including followup wells at the Dugong and Maha discoveries as well as a wild-cat at Dugong Tail. Dugong was discovered in the Norwegian portion of the North Sea in 2020. Neptune believes the prospect holds between 40–120 million BOE. Dugong is located 158 km west of Florø, Norway, at a water depth of 330 m, and is close to existing production facilities. The Dugong prospect comprises two reservoirs that lies at a depth between 3250–3500 m. The Maha discovery offshore East Kalimantan is estimated to hold gas resources in excess of 600 Bcf. In 2019, Neptune and its partners, Eni (operator) and Pertamina, were awarded the West Ganal production-sharing contract that holds the Maya find. An exploration well targeting the Dugong Tail prospect, adjacent to the south of the Dugong find, is slated for the third quarter of this year and will be drilled using Odjfell semisubmersible Deepsea Yantai. Interest Wanes in Norway’s Arctic Frontier Seven companies applied for new acreage in the Barents Sea in Norway’s latest licensing round, down from 26 in a similar round in 2013. The government had offered 125 new blocks in eight frontier regions of the Barents. More than 60% of the undiscovered hydrocarbons offshore Norway are in the Barents frontier, according to the nation’s petroleum directorate. However, appetites for frontier drilling have diminished as oil prices weakened and recent results from the region have disappointed. Companies that applied for the new acreage round were Norske Shell, Equinor, Idemitsu Petroleum Norge, Ineos E&P Norge, Lundin Norway, OMV Norge, and Var Energi. Oman Transfers Ownership of Massive Block 6 The government of Oman has transferred its stake in one of the Middle East’s largest oil blocks to a newly established firm. By royal decree, the new, state-controlled Energy Development Oman (EDO) will hold the country’s 60% stake in Block 6. The stake was moved from Petroleum Development Oman (PDO), another government-run company. Oman, which is struggling under a soaring budget deficit, is looking to finance its spending by leveraging its energy assets. Block 6 has a production capacity of 650,000 BOED. Shell holds 34% in the block, while Total holds the remaining 4%. The government appointed Haifa Al Khaifi as head of EDO in January. She joined from PDO and is also chairwoman of the Saudi Arabian unit of State Street Corp., the Boston-based custodian and money manager. EDO will also be able to invest abroad and deal in renewable-energy products.
30
Sengupta, Sobhan, and M. K. Chatterjee. "Evaluation of Semisubmersible Motion Characteristics." Marine Technology and SNAME News 23, no. 03 (July 1, 1986): 217–25. http://dx.doi.org/10.5957/mt1.1986.23.3.217.
Full textAbstract:
Semisubmersibles are the most widely used offshore mobile units for deepwater drilling. Because of their improved motion characteristics they provide a more stable drilling platform. This feature of improved motion characteristics has become an important cost-effective design consideration as larger and more expensive drilling units are needed for deeper water and harsher environments. This paper presents a simple analytical method to compute semisubmersible motion characteristics. Programmed in a microcomputer, this becomes an important tool for designers to identify the important parameters affecting the platform motions, to study their effects, and then to choose desirable values of these parameters for improved design. The program is verified with experimental data, and example applications are given.
31
Engelsen, Hilde, and Henrik Hannus. "Development of semi-submersible production vessels and its application to Australian waters." APPEA Journal 48, no. 1 (2008): 241. http://dx.doi.org/10.1071/aj07015.
Full textAbstract:
Semi-submersible platforms have a long history in the North Sea. In the beginning they were used mainly as mobile offshore drilling units, but in the last two decades the permanently moored semi-submersible production vessels have become widely used both as gas processing units and combination oil and gas production vessels. The design of production semi-submersibles evolved from that of drilling rigs, but there have since been significant improvements to the design of the hull and the topside configuration in relation to operational requirements and construction processes. The design methods have also been successfully adapted to areas with different environmental conditions, in combination with steel catenary risers and polyester mooring systems. On recent designs, simplifications of the hull systems are being implemented, which ease operation and enhance the passive safety. Finally, the semi-submersible production vessel’s application to Australian waters is discussed with focus on topside layout, hull design and mooring system design. Environmental conditions offshore northwest Australia are compared to North Sea and Gulf of Mexico conditions, along with vessel class and regulatory requirements.
32
Skoko, Ivica, Marinko Jurčević, and Diana Božić. "Logistics Aspect of Offshore Support Vessels on the West Africa Market." PROMET - Traffic&Transportation 25, no. 6 (December 16, 2013): 587–93. http://dx.doi.org/10.7307/ptt.v25i6.1258.
Full textAbstract:
With the rapidly increasing global energy needs, offshore oil production has become an attractive source of energy. Supplying offshore oil production installations is a complex logistics problem that hinges on many factors with significant uncertainties. So, it is critical to provide the necessary supplies and services without interruption. In a typical offshore oil production effort, oil companies charter most or all drilling units as well as offshore supply vessels (OSV). The type and duration of charter contract has direct impact on the project budget as vessels market is closely correlated with the world market crude oil price which can have daily significant fluctuations. As the region of West Africa is one of the world’s busiest offshore exploration and oil production markets employing 12% of the world’s fleet, exploring its issues, was taken to study the relations between daily OSV rates and crude oil price. The research results presented in this paper show correlation between OSV daily rates and crude oil price with broader fluctuations in crude oil price.
33
Kurfurst, P. J., and S. R. Dallimore. "Engineering geology of nearshore areas off Richards Island, N.W.T.: a comparison of stable and actively eroding coastlines." Canadian Geotechnical Journal 28, no. 2 (April 1, 1991): 179–88. http://dx.doi.org/10.1139/t91-025.
Full textAbstract:
Nearshore areas off northern Richards Island can be expected to show considerable variability in lithology, strengths, and geothermal setting both in a temporal and a spatial sense. Drilling and laboratory studies carried out along onshore–offshore transects at a stable coastal site and an actively eroding coastal site have identified six major stratigraphic units of Holocene and pre-Holocene (Wisconsinan) age. The main factors controlling the geotechnical properties of these sediments and their distribution are the occurrence of shallow permafrost beneath areas seasonally covered by landfast sea ice, rapid degradation of permafrost in areas farther offshore, ice content of thawing pre-Holocene sediments, and variability in coastal processes. Key words: nearshore deposits, engineering geology, permafrost, physical properties, acoustic properties.
34
Mrozowska, Alicja, and Piotr Mrozowski. "The Analysis of Maritime Accidents in 2017." Annual of Navigation 25, no. 1 (December 1, 2018): 233–52. http://dx.doi.org/10.1515/aon-2018-0016.
Full textAbstract:
AbstractStudy presents the analysis of accidents that took place in marine areas and on board of the sea units in 2017, including: vessel carrying passengers, cargo vessels and offshore drilling and production installations, as well as offshore support vessels. The aim of the article is to indicate a wide spectrum of events related to: total losses of vessels, accidents on boards of the vessels and other accidents which happened in marine areas. The study presents numerous data, which were presented in the form of graphs and tables, based on international reports and own experience gained during work experiences. The analysis also referred to data from previous years to show better spectrum of the present situation.
35
Southworth, Justina, and Jostein Fjogstad. "Shell Deep Water Exploration Drilling, the Sail and Drill Concept." International Oil Spill Conference Proceedings 2014, no. 1 (May 1, 2014): 299686. http://dx.doi.org/10.7901/2169-3358-2014-1-299686.1.
Full textAbstract:
The Shell Sail and Drill project is a 5 year exploration campaign, capable of operating in all ice-free waters. This multi-region project initiated in 2012, will commence first drilling operations in September 2013. The unique challenges of developing robust preparedness over multiple geographic locations, multiple business units and multiple operators are examined further in this paper. The Sail and Drill project has proactively challenged the conventional approach to oil spill contingency planning. It provides a multi-region integrated suite of emergency response documents. The OSCP delivers the core contingency planning for the drillship and accompanying support vessels These core global documents allow for full buy-in and understanding from the Shell business units involved. This is then supplemented by a wider location-specific plan which addresses oil spill response from strategic management through to operational work activities. Through a series of exercises and workshops, the Sail and Drill OSCP has expanded in remit. This has been achieved by working closely with multiple business units encouraging buy-in to the preparedness planning process across the project. The risks of operating in multiple locations are recognized in the OSCP. Mitigation measures include a comprehensive equipment package, which retains full redundancy and maximum flexibility. This is achieved by providing a robust offshore response capability supplemented by targeted shoreline response packages. Flexibility is achieved by having an equipment selection which covers a wide range of oil types and response site terrains. The structure of the packages provides a roaming offshore package in addition to a pair of enhanced shoreline response packages, capable of leap frogging from location to location. Redundancy is achieved by having sufficient equipment located in-country and in areas of future operations simultaneously. This allows personnel in the new operating locations to become fully competent with the equipment prior to drilling activities commencing. This is supported by a full equipment training and maintenance programme over the duration of the campaign. Over the years, OSRL as an industry operated body has been involved in a wide range of preparedness and response activities, from a large number of operators across the globe. The new approach adopted by the Sail and Drill campaign is unique and offers a new benchmark for all future preparedness and planning.
36
Zheng, Wen Pei, Jian Chun Fan, Lai Bin Zhang, and Dong Wen. "Measurement and Control System of Intense-Magnetic Memory Testing Equipment for Reusable Offshore Oil Well Tubing." Key Engineering Materials 439-440 (June 2010): 1624–27. http://dx.doi.org/10.4028/www.scientific.net/kem.439-440.1624.
Full textAbstract:
Oil well tubing is used in oil extraction in offshore oil well. Under the force of tubular columns, erosion and pressure of drilling fluids, the oil well tubing usually fails in long-term service, which always leads to accidents and stagnation of production. So it’s especially necessary to detect faults in tubing. Intense-magnetic memory testing equipment for reusable offshore oil well tubing is developed for this consideration. The equipment is composed of feeding machines, baiting machines, transport machines and a detection machine. Measurement and control system decides the running sequence logic of these components and obtains fault signals of tubing. The avoidance of transport machines for oil well tubing coupling makes the transport of tubing stable. The synchronization control of transport and detection of tubing decides the accurate location of faults. The automatic switch of both detection units and measurement of fault signals makes it convenient to detect oil well tubing of multiple sizes.
37
Bienen, B., and M. J. Cassidy. "Three-dimensional numerical analysis of centrifuge experiments on a model jack-up drilling rig on sand." Canadian Geotechnical Journal 46, no. 2 (February 2009): 208–24. http://dx.doi.org/10.1139/t08-115.
Full textAbstract:
Jack-up drilling rigs are usually founded on three shallow footings. Under wind, wave, and current loading offshore, the footings of these tall multi-footing systems transfer large moment loads in addition to self-weight, horizontal load, and even torsion to the underlying soil. To be able to deploy a jack-up safely at a particular offshore site, the unit’s capacity to withstand a 50 year return period storm is required to be checked in accordance with current guidelines (Site specific assessment of mobile jack-up units, The Society of Naval Architects & Marine Engineers). As the overall system behaviour is influenced significantly by the footing restraint, models that account for the complex nonlinear foundation–soil interaction behaviour are required to be integrated with the structural and loading models. Displacement-hardening plasticity theory has been suggested as an appropriate framework to formulate force-resultant models to predict shallow foundation behaviour. Recent research has extended such a model to account for six degree-of-freedom loading of circular footings on sand, allowing integrated structure–soil analysis in three dimensions. This paper discusses “class A” numerical predictions of experiments on a model jack-up in a geotechnical centrifuge, using the integrated modelling approach, and critically evaluates the predictive performance. The numerical simulations are shown to represent a significant improvement compared with the method outlined in the current guidelines.
38
Carpenter, Chris. "Invasive Sun Coral Species Challenges Decommissioning of Structures Offshore Brazil." Journal of Petroleum Technology 73, no. 08 (August 1, 2021): 58–59. http://dx.doi.org/10.2118/0821-0058-jpt.
Full textAbstract:
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30656, “Decommissioning of Subsea Structures in Brazil: Effect of Invasive Species and Genome Sequence of the Azooxanthellate Coral Tubastraea sp.,” by João Humberto Guandalini Batista, SPE, Repsol; Mauro Rebelo, Universidade Federal do Rio de Janeiro; and Giordano Soares-Souza, SENAI CETIQT, prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Decommissioning of offshore assets in Brazil is subject to high levels of uncertainty because of Tubastraea, an invasive species of sun coral. This species has a high capacity for dispersion and recruitment and has been associated with the replacement of native species in rocky shores, exerting a serious effect on native biodiversity. The complete paper explores the biology of the invasive species, aiming to identify methods to eliminate or diminish its spread. The authors write that data generated in this study will foster the development of effective technologies in coral-species management, whether species are invasive or threatened. Introduction Originally from the Coral Triangle in the Pacific Ocean—a highly diverse region with hundreds of coral species—Tubastraea was first observed in the Campos Basin in the 1980s. Tubastraea sp. have high fecundity and growth rates with the ability to reproduce asexually, establishing very dense populations. This fast reproduction allows larvae to outcompete native species in both natural and artificial substrates in the sea. Sun coral is extremely resistant to environmental change. It has been found in shallow waters, sometimes exposed to air, showing tolerance even to short periods of desiccation. Recently, new species have been identified in Brazilian waters, heightening concern over the proliferation of sun coral. In the past, the common understanding was that subspecies coccinea and tagusensis were those found in Brazilian waters. However, recent studies dedicated to the research of the Tubastraea genus raised suspicion of the presence of diaphana and aurea, with the possible occurrence of hybrids as well. The preference of Tubastraea is to live in structures that are static or mostly motionless, such as production platforms, subsea structures, and drilling rigs. This trait has made sun coral a major challenge for the local oil and gas industry. While in the Campos Basin, the main objective is to decrease dispersion of already bioencrusted production units and subsea structures, in the Santos Basin, the goal is to avoid colonization in structures in operation or those scheduled to be installed soon. To further complicate matters, drilling and intervention vessels and rigs are contracted to service both basins. They work in dynamic-positioning mode, stationary around the production units and subsea structures for lengths of time that exceed the reproduction cycle time of the sun coral, allowing larval dispersion.
39
Agoha, C. C., A. I. Opara, O. C. Okeke, C. N. Okereke, C. N. Onwubuariri, F. B. Akiang, L. J. Osaki, and I. A. Omenikolo. "Integrated 3D geomechanical characterization of a reservoir: case study of "Fuja" field, offshore Niger Delta, Southern Nigeria." Journal of Petroleum Exploration and Production Technology 11, no. 10 (August 26, 2021): 3637–62. http://dx.doi.org/10.1007/s13202-021-01244-9.
Full textAbstract:
Abstract3D geomechanical characterization of "Fuja" field reservoirs, Niger Delta, was carried out to evaluate the mechanical properties of the reservoir rock which will assist in reducing drilling and exploitation challenges faced by operators. Bulk density, sonic, and gamma-ray logs from four wells were integrated with 3D seismic data and core data from the area to estimate the elastic and inelastic rock properties, pore pressure, total vertical stress, as well as maximum and minimum horizontal stresses within the reservoirs from empirical equations, using Petrel and Microsoft Excel software. 3D geomechanical models of these rock properties and cross-plots showing the relationship between the elastic and inelastic properties were also generated. From the results, Young's modulus, bulk modulus, bulk compressibility, shear modulus, Poisson's ratio, and unconfined compressive strength recorded average values of 5.11 GPa, 5.10 GPa, 0.023 GPa−1$$,$$ , 2.39 GPa, 0.39, and 39.0 GPa, respectively, in the sand, and 6.08 GPa, 6.09 Gpa, 0.016 GPa−1 2.84 GPa, 0.42, and 42.3 GPa, respectively, in shale, implying that the sand is less elastic and ductile and will deform before the shale under similar stress conditions. Results also revealed mean pore pressures of 13,248 psi and 15,220 psi in sand and shale units, respectively, mean total vertical stress of 28,193 psi, mean maximum horizontal stress of 26,237 psi, and mean minimum horizontal stress of 21,532 psi. From the geomechanical models, the rock elastic and inelastic parameters revealed higher values around the northeastern and parts of the eastern and western portions of the reservoir implying that mechanical rock deformation will be minimal in these sections of the field compared to other sections during drilling and post-drilling activities. The generated cross-plots indicate that a relationship exists between the elastic rock properties and unconfined compressive strength. Stress estimations within the reservoirs in relation to the obtained elastic and rock strength parameters show that the reservoirs are stable. These results will be invaluable in mitigating exploration and exploitation challenges.
40
Jafar, A. S., I. S. El-Ageli, and H. H. Al-Attar. "Discussion and Comparison of Horizontal-Well Performance in Bouri Field." SPE Reservoir Evaluation & Engineering 3, no. 06 (December 1, 2000): 567–72. http://dx.doi.org/10.2118/68321-pa.
Full textAbstract:
Summary Seven horizontal wells were drilled in Bouri field, offshore Libya, and put on production between 1989 and 1992. This paper presents the experience gained in producing and monitoring these wells over the past few years. Comparison of well basic characteristics and performances with offset conventional wells indicates their higher productivity and general superior performance. Different monitoring activities conducted on these wells are discussed, including transient test analyses and production logs. Free gas production was found to be related to the combined phenomena of coning and fracture flow mechanism. These discussions show that, in most of the cases, production of water and gas is inevitable as long as economic oil rates are to be maintained. The targets set for these wells in terms of recovery increase and production troubles reduction were at least partially fulfilled. Introduction Bouri field is an elongated E-W-orientated anticline located in the Libyan offshore about 130 km NW of Tripoli. The field was discovered in the 1970s and started on production in 1988, from the eastern two sectors (3 and 4). The pay interval is the uppermost member of the Metlaoui formation from the Early Eocene age, at an average depth of 8,000 ft subsea level, with a lithology dominated by Nummulitic limestones. The reservoir comprises a thick oil ring of around 300 ft overlaid by an extended primary gas cap and underlain by water. The resultant drive mechanism is a combination of aquifer activity and gas-cap expansion. Different fault sets cut the structure with varied local intensity, affecting more dominantly the southern flank, where water advance is mostly appreciated. These faults and their associated network of fractures and microfractures affect the characteristics of the rocks and influence, to one degree or another, the productivity and the flow dynamics in the reservoir. Horizontal Wells Of the 55 wells drilled for field development, seven were drilled as horizontals (HWS). The other wells are conventionals (CWS), comprising slanted wells with up to 65°, and two verticals. The original objective was to efficiently drain the reservoir oil below the gas cap (Fig. 1). Optimizing the production rates while keeping low drawdowns should help to minimize the gas coning tendency. Geological Brief. The particular target of all horizontal drilling in the field was the stratigraphic layer of Metlaoui formation designated as U2. The layer forms the lowermost interval of the pay zone (Fig. 2) and is further divided into three subunits (from bottom to top), U2a, U2b, and U2c. The first subunit represents a zone of good petrophysical properties with an average thickness that exceeds 80 ft in the interested area. Besides having excellent lateral homogeneity, it also contains some 20% of the original oil in place (OOIP) in the developed area. It was the target of most of the HWS in Sector 4. The unit gradually diminishes toward the west, and disappears completely in the Sector 3 area. The intermediate subunit U2b is composed mainly of cemented Nummulitic limestone that forms a compact 20- to 30-ft well traceable layer extending all the way above U2a. It represents a presumed natural barrier to gas expansion, further promoting U2a as a favorable position for the HWS. The upper subunit U2c has a much wider areal extension than the lower two, covering the total developed area with an average thickness of 80 ft and with fairly good properties. It was the target of the two horizontal wells in Sector 3 and one in Sector 4. Relevant well information is found in Table 1. On the other hand, a thick zone of poor-porosity rocks that lies directly below layer U2 was envisaged to hamper the water advancement. The first five horizontals, all in Sector 4, were actually located below the gas cap. The other two were drilled in a part of the field with highly complicated structural setting owing to extensive faulting (Sector 3), thus hitting the pay zone at the edge of the gas cap, as seen in Fig. 1. Completion and Stimulation. The main objectives of completing and stimulating the HWS in the field were to remove the formation damage and to obtain the maximum contributing length along the completed interval. Early experience in the field had highlighted the necessity of acid treatment to start production, as the Nummulitic porosity was being badly damaged by drilling operations. Following the poor experience of the stimulation and the consequent flow profile in the first horizontal (B4-09H), several variations in completion design and stimulation techniques were attempted. Feedback from transient testing and production logging results helped to optimize the implemented specific acid volume as 1 bbl/ft. Spotting acid by coiled tubing with movement along the perforated interval was found very effective. The use of external inflatable casing packers (EICP) with selective stimulation of intervals1 was an extra aid. A summary of data is shown in Table 2, together with the resultant perforation efficiency (PE) defined as the ratio of the contributing to total completed interval. Acid treatments successfully stimulated the HWS to skin factors of -4 (Tables 3 and 4), recalling that the wells were not able to flow initially. Monitoring Activities. Routine Flow Testing and Production Allocation. Flow tests were run on the basis of one test per month with a two-phase separator. In this way, accurate production allocation is allowed by means of continuous updating of deliverability curves, in addition to close observation of any change in well performance caused by free gas or water flow. Produced water shows the tendency to form a strong emulsion with oil. Because of the method of sampling for water-cut determination, oil rate is usually underestimated. Production results in high-water-cut wells are considered less reliable. Static Pressure. Initial static pressure for each well was measured through stabilized buildups. The low frequency of static pressure records on horizontal wells is caused by the long shut-in times required for stabilization, with the corresponding loss of production. Nevertheless, some 26 pressure surveys were run on those wells in total. The magnitude and the trend of decline in pressure (Fig. 3) reflect the reservoir pressure behavior in the field.
41
Evans, Sian L., and Christopher A. L. Jackson. "Intra-salt structure and strain partitioning in layered evaporites: implications for drilling through Messinian salt in the eastern Mediterranean." Petroleum Geoscience 27, no. 4 (April 7, 2021): petgeo2020–072. http://dx.doi.org/10.1144/petgeo2020-072.
Full textAbstract:
We use 3D seismic reflection data from the Levant margin, offshore Lebanon to investigate the structural evolution of the Messinian evaporite sequence, and how intra-salt structure and strain varies within a thick salt sheet during early-stage salt tectonics. Intra-Messinian reflectivity reveals lithological heterogeneity within the otherwise halite-dominated sequence. This leads to rheological heterogeneity, with the different mechanical properties of the various units controlling strain accommodation within the deforming salt sheet. We assess the distribution and orientation of structures, and show how intra-salt strain varies both laterally and vertically along the margin. We argue that units appearing weakly strained in seismic data may in fact accommodate considerable subseismic or cryptic strain. We also discuss how the intra-salt stress state varies through time and space in response to the gravitational forces driving deformation. We conclude that efficient drilling through thick, heterogeneous salt requires a holistic understanding of the mechanical and kinematic development of the salt and its overburden. This will also enable us to build better velocity models that account for intra-salt lithological and structural complexity in order to accurately image sub-salt geological structures.
42
van Oorschot, Rene, Willeke Smit, and Anzhela Glebova. "The Grove Field, Blocks 49/10a, 49/9c, 49/10c, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 180–88. http://dx.doi.org/10.1144/m52-2018-79.
Full textAbstract:
AbstractThe Grove gas field is located in the Southern North Sea, within the UK offshore licence Blocks 49/10a, 49/9c and 49/10c. The field lies 180 km east of the Humberside coast and 4 km from the UK–Netherlands median line on the western margin of the Cleaver Bank High. The reservoir consists of late Westphalian C fluvial red beds interbedded with mud-prone floodplain deposits. Grove was put on production in 2007 through a single normally unmanned platform which is connected to the Markham J6A facilities by means of a 13.4 km 10-inch pipeline and subsequently exported to Den Helder in the Netherlands. The field has been developed by means of six production wells, targeting a variety of fault blocks and sandstone units. Reservoir complexity due to differential erosion, heterogeneity and faulting has presented development challenges and productivity per well is highly variable. Additionally, the evaporites within the overlying Zechstein Group present drilling and well integrity issues.
43
McConachie, B. A., P. W. Stainton, M. G. Barlow, and J. N. Dunster. "THE OFFSHORE CARPENTARIA BASIN-GULF OF CARPENTARIA, NORTH QUEENSLAND." APPEA Journal 34, no. 1 (1994): 614. http://dx.doi.org/10.1071/aj93047.
Full textAbstract:
The Carpentaria Basin is late Jurassic to early Cretaceous in age and underlies most of the Gulf of Carpentaria and surrounding onshore areas. The Carpentaria Basin is stratigraphically equivalent to the Eromanga and Papuan Basins where similar reservoir rocks produce large volumes of hydrocarbons.Drillholes Duyken–1, Jackie Ck–1 and 307RD12 provide regional lithostratigraphic and tectonic control for the Q22P permit in the offshore Carpentaria Basin. Duyken–1 penetrated the upper seal section in the Carpentaria Basin and a full sequence through the overlying Karumba Basin. Jackin Ck–1 intersected the lower reservoir units and a condensed upper seal section of the Carpentaria Basin. Coal drillhole 307RD12 tested the late Jurassic to early Cretaceous reservoir section in the Carpentaria Basin and also intersected an underlying Permian infrabasin sequence.Little is known of the pre Jurassic sedimentary section below the offshore Carpentaria Basin but at least two different rock packages appear to be present. The most encouraging are relatively small, layered, low velocity, channel and half-graben fill, possibly related to Permian or Permo-Triassic sedimentary rocks to the east in the Olive River area. The other packages consist of poorly defined, discontinuous, high velocity rocks believed to be related to those of the Bamaga Basin which have been mapped further north.During the period 1990-1993 Comalco Aluminium Limited reprocessed 2188 km of existing seismic data and acquired 2657 km of new seismic data over the offshore Carpentaria Basin. When combined with onshore seismic and the results of drilling previously undertaken by Comalco near Weipa on northwestern Cape York Peninsula, it was possible to define a significant and untested play in the Carpentaria Depression, the deepest part of the offshore Carpentaria Basin.The main play in the basin is the late Jurassic to early Cretaceous reservoir sandstones and source rocks, sealed by thick early Cretaceous mudstones. Possible pre-Jurassic source rocks are also present in discontinuous fault controlled half-grabens underlying the Carpentaria Basin. New detailed basin modelling suggests both the lower part of the Carpentaria Basin and any pre Jurassic section are mature within the depression and any source rocks present should have expelled oil.
44
Davies, D. K., R. K. Vessell, and J. B. Auman. "Improved Prediction of Reservoir Behavior Through Integration of Quantitative Geological and Petrophysical Data." SPE Reservoir Evaluation & Engineering 2, no. 02 (April 1, 1999): 149–60. http://dx.doi.org/10.2118/55881-pa.
Full textAbstract:
Summary This paper presents a cost effective, quantitative methodology for reservoir characterization that results in improved prediction of permeability, production and injection behavior during primary and enhanced recovery operations. The method is based fundamentally on the identification of rock types (intervals of rock with unique pore geometry). This approach uses image analysis of core material to quantitatively identify various pore geometries. When combined with more traditional petrophysical measurements, such as porosity, permeability and capillary pressure, intervals of rock with various pore geometries (rock types) can be recognized from conventional wireline logs in noncored wells or intervals. This allows for calculation of rock type and improved estimation of permeability and saturation. Based on geological input, the reservoirs can then be divided into flow units (hydrodynamically continuous layers) and grid blocks for simulation. Results are presented of detailed studies in two, distinctly different, complex reservoirs: a low porosity carbonate reservoir and a high porosity sandstone reservoir. When combined with production data, the improved characterization and predictability of performance obtained using this unique technique have provided a means of targeting the highest quality development drilling locations, improving pattern design, rapidly recognizing conformance and formation damage problems, identifying bypassed pay intervals, and improving assessments of present and future value. Introduction This paper presents a technique for improved prediction of permeability and flow unit distribution that can be used in reservoirs of widely differing lithologies and differing porosity characteristics. The technique focuses on the use and integration of pore geometrical data and wireline log data to predict permeability and define hydraulic flow units in complex reservoirs. The two studies presented here include a low porosity, complex carbonate reservoir and a high porosity, heterogeneous sandstone reservoir. These reservoir classes represent end-members in the spectrum of hydrocarbon reservoirs. Additionally, these reservoirs are often difficult to characterize (due to their geological complexity) and frequently contain significant volumes of remaining reserves.1 The two reservoir studies are funded by the U.S. Department of Energy as part of the Class II and Class III Oil Programs for shallow shelf carbonate (SSC) reservoirs and slope/basin clastic (SBC) reservoirs. The technique described in this paper has also been used to characterize a wide range of other carbonate and sandstone reservoirs including tight gas sands (Wilcox, Vicksburg, and Cotton Valley Formations, Texas), moderate porosity sandstones (Middle Magdalena Valley, Colombia and San Jorge Basin, Argentina), and high porosity reservoirs (Offshore Gulf Coast and Middle East). The techniques used for reservoir description in this paper meet three basic requirements that are important in mature, heterogeneous fields.The reservoir descriptions are log-based. Flow units are identified using wireline logs because few wells have cores. Integration of data from analysis of cores is an essential component of the log models.Accurate values of permeability are derived from logs. In complex reservoirs, values of porosity and saturation derived from routine log analysis often do not accurately identify productivity. It is therefore necessary to develop a log model that will allow the prediction of another producibility parameter. In these studies we have derived foot-by-foot values of permeability for cored and non-cored intervals in all wells with suitable wireline logs.Use only the existing databases. No new wells will be drilled to aid reservoir description. Methodology Techniques of reservoir description used in these studies are based on the identification of rock types (intervals of rock with unique petrophysical properties). Rock types are identified on the basis of measured pore geometrical characteristics, principally pore body size (average diameter), pore body shape, aspect ratio (size of pore body: size of pore throat) and coordination number (number of throats per pore). This involves the detailed analysis of small rock samples taken from existing cores (conventional cores and sidewall cores). The rock type information is used to develop the vertical layering profile in cored intervals. Integration of rock type data with wireline log data allows field-wide extrapolation of the reservoir model from cored to non-cored wells. Emphasis is placed on measurement of pore geometrical characteristics using a scanning electron microscope specially equipped for automated image analysis procedures.2–4 A knowledge of pore geometrical characteristics is of fundamental importance to reservoir characterization because the displacement of hydrocarbons is controlled at the pore level; the petrophysical properties of rocks are controlled by the pore geometry.5–8 The specific procedure includes the following steps.Routine measurement of porosity and permeability.Detailed macroscopic core description to identify vertical changes in texture and lithology for all cores.Detailed thin section and scanning electron microscope analyses (secondary electron imaging mode) of 100 to 150 small rock samples taken from the same locations as the plugs used in routine core analysis. In the SBC reservoir, x-ray diffraction analysis is also used. The combination of thin section and x-ray analyses provides direct measurement of the shale volume, clay volume, grain size, sorting and mineral composition for the core samples analyzed.Rock types are identified for each rock sample using measured data on pore body size, pore throat size and pore interconnectivity (coordination number and pore arrangement).
45
Camara, Rodrigo, Júlio César Ribeiro, Marcos Gervasio Pereira, Ana Caroline Rodrigues Silva, Joel Quintino Oliveira Filho, and Everaldo Zonta. "PRODUCTION OF SEEDLINGS OF COLUBRINA GLANDULOSA PERKINS WITH DRILLING WASTE FROM OIL WELLS AND MYCORRHIZAL INOCULATION." FLORESTA 51, no. 3 (June 22, 2021): 731. http://dx.doi.org/10.5380/rf.v51i3.72486.
Full textAbstract:
Oil exploration, whether onshore or offshore, results in residues from the drilling of wells, called gravel. The use of this environmental liability in the production of seedlings for forest restoration could contribute to an appropriate destination for this waste. In the present study, the objective was to evaluate the effect of the substrate formulated with gravel, with and without inoculation with arbuscular mycorrhizal fungi (AMF), on the growth and nutritional status of seedlings of Colubrina glandulosa. The design used was completely randomized in a 5x2 factorial scheme, with five gravel doses (0, 5, 10, 15, and 20%), with and without inoculation with a mixture of AMF spores (Gigaspora margarita¸ Rhizophagus clarus, and Dentiscutata heterogama) with six repetitions, totaling 60 experimental units. Height (H) and stem diameter (SD) were evaluated at 30, 60, 90, and 120 days after seedling transplantation, when the plants were sectioned in shoots (branches + leaves) and roots, to determine dry biomass of shoots (DMS) and of roots (DMR), leaf area index (LAI), rate of length of fine roots colonized by AMF (COL), and chemical composition. The substrate obtained with the application of the lowest gravel dose (5%), without the mycorrhizal inoculation, provided significant increments in H, SD, LAI, DMS, DMR, and COL of the seedlings of Colubrina glandulosa, when compared to the other gravel doses and the presence of mycorrhizal inoculation, 120 days after seedling transplantation.
46
Korn, B. E., R. P. Teakle, D. M. Maughan, and P. B. Siffleet. "THE GERYON, ORTHRUS, MAENAD AND URANIA GAS FIELDS, CARNARVON BASIN, WESTERN AUSTRALIA." APPEA Journal 43, no. 1 (2003): 285. http://dx.doi.org/10.1071/aj02015.
Full textAbstract:
The Geryon, Orthrus, Maenad and Urania Gas Fields are located in permit WA-267-P in approximately 1,200 m of water, and between 35 km northwest and 70 km north of the Gorgon Gas Field in the offshore Carnarvon Basin of Western Australia. Five wells were drilled in these fields between August 1999 and February 2001 as part of a six-well, three-year obligatory drilling program. The primary objectives were late Triassic sandstones of the upper Mungaroo Formation. The Geryon and Urania Fields are three-way footwall structures, while the Orthrus and Maenad Fields comprise four-way horst structures where progressively older units subcrop against the Callovian Unconformity. All objective reservoirs were amplitude associated and had strong AVO signatures, which was instrumental in the high exploration success rate and excellent exploration prediction of OGIP from seismic data.This paper will briefly discuss the description of late Triassic and early Jurassic reservoirs and the transition of the AA sand of the Mungaroo Formation from fluvial to marginal marine facies in the Greater Gorgon Area, the recent drilling results of the Triassic Prospects in WA-267-P, and the geophysical attributes of the AA sand Mungaroo Formation reservoirs.The WA-267-P Triassic Gas Fields are estimated to contain approximately 210 billion m3 (7.4 TCF) recoverable sales gas. The close proximity of these Triassic gas fields to each other, the clean gas composition and size of resource base suggests these fields are excellent candidates for a future gas development in Western Australia.
47
Feng, Ding, Xiao Fei Chang, Xian Yong Zhang, Shou Yong Li, Chao Ruan, and Yu Xie. "The Research to Hydrocyclone Desander of Sand Removing Based on Crude Oil." Applied Mechanics and Materials 152-154 (January 2012): 1336–41. http://dx.doi.org/10.4028/www.scientific.net/amm.152-154.1336.
Full textAbstract:
The fractional volume of the reservoir sand shall be taken to the ground when the crude oil is brought up from the ground. With the deepening of the oil extraction the sand content of oil recovery is increasing. Although many measures have been used such as prevent sand, block sand and so on, the viscosity of heavy oil is big and the fractional of sand is carried into the crude oil gathering system inevitably, causing a series of problems at ground equipment, having a serious impact on the normal production and gathering of crude oil. The larger size of sand can be removed by the sedimentation and the smaller sand can be removed by hydrocyclone devices. Hydrocyclone is a separation plant used to separate non-uniform phase mixtures. It can be used to complete the liquid clarification and to wash particles, liquid degassing and grit removal, grading and classification of solid particles and the separation of two non-miscible liquids and others. Hydrocyclone separation technique is simple and convenient operation, high separation efficiency, no rotating units, small size and easy to realize automatic control. On the offshore platform，if the sand mixed with oil is discharged into sea unsatisfactory the standard, it will pollute the sea. It will cause a serious of marine pollution; this is a problem that should be solved quickly. This paper discusses the requirements for the design of the hydrocyclone desander equipment with compact structure, applicable to offshore drilling platforms，and carrying out CFD simulation, the results showing that the particle size of 75 of sand, grit removal efficiency above 90%.
48
Rudenko, Mikhail Fedorovich, Yulia Victorovna Shipulina, and Alexandra Mikhailovna Rudenko. "Using low-temperature technologies to prevent emergency situations at sea and rivers during extraction, production and transportation of hydrocarbon raw materials." Vestnik of Astrakhan State Technical University. Series: Marine engineering and technologies 2020, no. 1 (February 17, 2020): 7–12. http://dx.doi.org/10.24143/2073-1574-2020-1-7-12.
Full textAbstract:
The paper highlights the chemically hazardous objects of marine and river infrastructure: offshore drilling platforms and oil production platforms; pipelines transporting liquid and gaseous hydrocarbon fuels along the sea bottom and above the ground; marine tankers transporting oil, fuel oil, gaseous and liquid ammonia; coastal terminals handling and shipping hydrocarbon raw materials, distillation products; gas producing plants and oil refineries; storage facilities for chemi-cally hazardous substances, etc. There are proposed new technologies for combating oil emissions during deep-water drilling, as well as for safe ways of transporting hydrocarbons through subsea pipelines and by oil tankers. These technologies are based on the methods of using low-temperature freons and cryogenic liquids. There are considered the methods of using machine cooling technologies, where the cascade refrigeration units work on various refrigerants, as well as using solid carbon dioxide and liquid nitrogen. Liquid nitrogen having a low boiling point (about minus 196C) has a higher rate of seawater freezing and forms stable ice layers on flat and cylindrical surfaces. There are given the examples of the experimental data to determine the growth rate of ice in the water frozen by liquid nitrogen. There has been given the chart of an underwater cryo-cuvette consisting of a metal panel with sockets, heat-insulated barrels, a tank for storing liquid nitrogen,
a nozzle for filling the cryoagent, adjusting eyebolts, an object for freezing and transportation, and a safety valve. The underwater cryo-cuvette is designed to work with barrel-shaped objects. Envi-ronmental safety of transportation and production of natural hydrocarbon raw materials is signifi-cantly improved in the course of operation of the new technologies.
49
Cheng, Ning, and Mark Jason Cassidy. "Development of a force–resultant model for spudcan footings on loose sand under combined loads." Canadian Geotechnical Journal 53, no. 12 (December 2016): 2014–29. http://dx.doi.org/10.1139/cgj-2015-0597.
Full textAbstract:
Spudcans are typical foundations used in shallow to moderate-depth water oil and gas fields to support jack-up drilling units. Understanding the behaviour of spudcans under combined loadings is crucial to the overall response of the jack-up structure. This paper presents the development of a strain-hardening plasticity model for a spudcan footing on loose sand. Most of the model components are developed from direct centrifuge observations. The centrifuge tests were performed at an acceleration of 100 times that of the Earth’s gravity on a model spudcan footing subjected to combined vertical, horizontal, and moment loads. All the experiments have been designed and conducted to allow the results to be interpreted with a strain-hardening plasticity framework. Combined loads were applied by using a novel apparatus, which enables independent vertical, horizontal, and rotational movements of the footing. Test results also revealed the existence of a three dimensional sliding surface that intersects with the conventional yield surface. This additional surface has been defined analytically. Retrospective simulation of the experimental data using the plasticity model confirms the model’s capability for use in predicting the behaviour of larger spudcan applications offshore.
50
JPT staff, _. "E&P Notes (May 2021)." Journal of Petroleum Technology 73, no. 05 (May 1, 2021): 14–17. http://dx.doi.org/10.2118/0521-0014-jpt.
Full textAbstract:
Dugong Reserve Estimate Tightens on New Well Results Neptune Energy redefined the estimated reserves at its Dugong discovery in the Norwegian sector of the North Sea to between 40–108 million BOE based on the results of appraisal well 34/4-16 S. Prior to this appraisal, the operator believed the prospect could hold as much as 120 million BOE. The main objective of the well was achieved by establishing the oil/water contact. Neptune Energy said the new range will be subject to further detailed analysis and review, and a drillstem test on the well is planned at a later stage. The appraisal well was drilled using the Odjfell-operated semisubmersible Deepsea Yantai in about 330 m of water. The Dugong discovery will either be linked to nearby infrastructure or developed as a standalone development. Dugong is located 158 km west of Florø, Norway, and is close to the existing production facilities of the Snorre and Statfjord fields. The Dugong license partners are Neptune Energy (operator and 45%), Petrolia NOCO (20%), Idemitsu Petroleum Norge (20%), and Concedo (15%). Oselvar P&A Work Underway Decommissioning of the DNO Norge-operated Oselvar field has kicked off with the operator contracting semisubmersible Borgland Dolphin for plug-and-abandonment work. Oselvar is in the southern part of the Norwegian sector in the North Sea, 20 km southwest of the Ula field. The water depth is 70 m. Oselvar was discovered in 1991, and the plan for development and operation was approved in 2009. The field was developed via a trio of subsea wells tied to Ula. Production started in 2012 and ended in 2018. The Borgland Dolphin was moved to the field on 20 March. The rig recently went through a series of upgrades including the installation of new shale shakers, new standpipe manifold, an upgraded drilling control system, and an upgraded helideck. Decommissioning must be completed by the end of 2022. Equinor Green Lights FPSO for Brazil’s BM-C-33 Development Equinor, together with license partners Repsol Sinopec Brasil and Petrobras, have approved an FPSO-based development concept for BM-C-33, a gas/condensate field located in the Campos Basin pre-salt in Brazil. Subsea wells will be tied back to the FPSO located at the field. Gas and oil/condensate will be processed at the floater to sales specifications and exported. Crude will be offloaded by shuttle tankers and shipped to the international market after ship-to-ship transfer. A newbuild hull has been selected to accommodate the field’s planned 30-year lifetime. “BM-C-33 holds substantial volumes of gas,” said Veronica Coelho, Equinor’s country manager in Brazil. “A completion of the ongoing liberalization of the natural gas market in Brazil in line with the current plan, is key for the further development of the project. BM-C-33 is an asset that can generate value for the society, both through the creation of direct and indirect jobs, ripple effects, and through a gas supply that can induce industrial growth, as has happened in other countries.” Gas export capacity is planned for 16 million cubic meters per day with average exports expected to be 14 million cubic meters per day. Daily oil processing capacity is of 20,000 cubic meters per day. The gas-export solution is based on an integrated offshore gas pipe-line from the FPSO to a new dedicated onshore gas-receiving facility inside the Petrobras TECAB site at Cabiúnas, before connecting to the domestic gas-transmission network. Lundin Makes Small Discovery Near Edvard Grieg Lundin Energy Norway encountered a 10-m oil column with its wildcat well 16/4-13 S about 15 km south of the Edvard Grieg field in the central part of the North Sea. The operator added that about 7 m of the encountered column was of moderate to poor reservoir quality. The oil/water contact was encountered 1950 m below the sea surface. The entire reservoir, including the water zone, comprises conglomeratic sandstones in a thickness of about 380 m. Preliminary estimates place the size of the discovery between 0.5 and 1.4 million cubic meters of recoverable oil equivalent. The licensees will assess the discovery regarding a possible tie-in to the Solveig field. The well was drilled by Seadrill semisubmersible West Bollsta and will be permanently plugged and abandoned. The rig will now move to drill the 16/4-BA-1H production well on the Solveig field. Wintershall Gets Permit for Bergknapp Appraisal The Norwegian Petroleum Directorate granted Wintershall Dea Norge a drilling permit for well 6406/3-10 A to spud a follow-up probe to a discovery made in April 2020. The Bergknapp appraisal will be drilled from the Odjfell semisubmersible Deepsea Aberdeen once the rig has concluded the drilling of wildcat well 6507/4-2 S for Wintershall in production license 211. The Bergknapp appraisal will be drilled about 8 km west of the Maria field in the Norwegian Sea. The discovery well 6406/3-10 intersected an oil column of at least 60 m in the Garn formation and an oil column of at least 120 m in the Tilje formation. Preliminary estimates of the Bergknapp discovery indicate it could hold between 26–97 million BOE. The find is in production license 836 S where Wintershall is the operator and holds a 40% stake. The other licensees are DNO Norge (30%) and Spirit Energy Norway AS (30%). The area in this license comprises parts of Blocks 6406/2 and 6406/3. Guyana Says Liza Hits First-Phase Capacity Guyana’s President Irfaan Ali announced that the first phase of the Liza offshore crude project had achieved its intended full-production capacity of around 130,000 B/D. Ali told virtual attendees at the Guyana Basin Summit that he expected an additional 10 exploration and appraisal wells to be drilled off Guyana this year. He said the second phase of the Liza project, operated by ExxonMobil, would begin in 2022. The consortium led by Exxon, which includes partners Hess and CNOOC Ltd., has made 18 discoveries containing more than 8 billion bbl of recoverable oil and gas in Guyana’s Stabroek block. Equinor and Partners in Barents Bounty Equinor and partners Vår Energi and Petoro have struck oil in exploration well 7220/7-4 in production license 532 in the Barents Sea. Recoverable resources are so far estimated at between 31–50 million BOE. The well was drilled about 10 km southwest from the well 7220/8-1 on the Johan Castberg field. “Succeeding in the Barents Sea requires perseverance and a long-term perspective,” says Nick Ashton, Equinor’s senior vice president for exploration in Norway. “This discovery strengthens our belief in the opportunities that exist, not least around the Castberg, Wisting, Snøhvit, and Goliat areas.” The well, drilled by semisubmersible Transocean Enabler, struck 109 m of oil in the Stø and Nordmela formations. The top reservoir was encountered at a vertical depth of 1788 m below sea level. The expected gas cap was not encountered in the well. The well was not formation tested, but extensive data acquisition and sampling took place. Equinor said further development of the discovery toward the planned infrastructure for the Johan Castberg field will be considered at a later stage. Exploration well 7220/7-4 is the first of four planned exploration wells for Equinor in the Barents Sea this year. Eni Strikes Light Oil at Cuica Eni has made a new light-oil discovery in Block 15/06 at its Cuica prospect in the deep waters offshore Angola. The prospect is located inside the Cabaça Development Area and close to the Armada Olombendo FPSO (East Hub). Eni estimates Cuica could hold between 200 and 250 million bbl of oil in place. The Cuica-1 NFW was drilled as a deviated well by Seadrill-operated drillship Sonagol Libongos in 500 m of water and reached a total vertical depth of 4100 m, encountering an 80-m total column of reservoir of light oil (38 °API) in sandstones of Miocene age with good petrophysical properties. The discovery well is going to be sidetracked up-dip to be placed in an optimal position as a producer well. According to Eni, data collection from the well indicates an expected production capacity of around 10,000 BOPD. Cuica is the second significant oil discovery inside the existing Cabaça Development Area. The well location, intentionally placed close to East Hub’s subsea network, will allow a fast-track tie-in of the exploration well and relevant production. Eni expects the well could be on line within 6 months. Following the discoveries of Kalimba, Afoxé, Ndungu, Agidigbo, Agogo and appraisals achieved between 2018 and 2020, Cuica represents the first commercial discovery in Block 15/06 after the relaunch of the exploration campaign post-2020 COVID-19 pandemic. The discovery confirms the exploration potential of the block. A 3-year extension of the exploration period of Block 15/06 was recently granted until November 2023. The Block 15/06 joint venture comprises Eni (operator, 36.8421%), Sonangol P&P (36.8421%), and SSI Fifteen Ltd. (26.3158%). No Injuries Reported in West Mira Incident An equipment failure onboard Northern Ocean semisubmersible West Mira resulted in production equipment descending to the seabed. The rig owner said no one was injured and the well at the location was secured “with three barriers in place.” The unit was in the process of lowering the equipment on the Wintershall-operated Nova field. “While lowering a x-mas tree from West Mira, the winch wire snapped when the tree was five meters below the sea surface. The x-mas tree sunk to the seafloor 368 meters below water level. Eight people were working in the area of the rig where the incident occurred in safe distance from moving equipment,” said Wintershall. The rig manager, Seadrill Europe Management AS, and Wintershall are conducting investigations into the incident and have agreed to a plan to secure the production equipment. “A remote operated vehicle (ROV) was sent to the seafloor to assess the situation,” added the oil company. “The ROV survey showed no risk of discharge of well fluids or hydrocarbons and the x-mas tree has been localized on the template.”