Academic literature on the topic 'Bottom water-drive oil and gas condensate reservoirs'
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Journal articles on the topic "Bottom water-drive oil and gas condensate reservoirs"
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Huang, Quan Hua, and Xing Yu Lin. "Prediction of water breakthrough time in horizontal Wells in edge water condensate gas reservoirs." E3S Web of Conferences 213 (2020): 02009. http://dx.doi.org/10.1051/e3sconf/202021302009.
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Horizontal Wells are often used to develop condensate gas reservoirs. When there is edge water in the gas reservoir, it will have a negative impact on the production of natural gas. Therefore, reasonable prediction of its water breakthrough time is of great significance for the efficient development of condensate gas reservoirs.At present, the prediction model of water breakthrough time in horizontal Wells of condensate gas reservoir is not perfect, and there are mainly problems such as incomplete consideration of retrograde condensate pollution and inaccurate determination of horizontal well seepage model. Based on the ellipsoidal horizontal well seepage model, considering the advance of edge water to the bottom of the well and condensate oil to formation, the advance of edge water is divided into two processes. The time when the first water molecule reaches the bottom of the well when the edge water tongue enters is deduced, that is, the time of edge water breakthrough in condensate gas reservoir.The calculation results show that the relative error of water breakthrough time considering retrograde condensate pollution is less than that without consideration, with a higher accuracy. The example error is less than 2%, which can be effectively applied to the development of edge water gas reservoir.
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Huang, Quan Hua, Hong Jun Ding, and Xing Yu Lin. "A productivity prediction method for condensate gas reservoir." E3S Web of Conferences 213 (2020): 02001. http://dx.doi.org/10.1051/e3sconf/202021302001.
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At present, multiphase flow productivity calculation requires many parameters, and most of them only consider oil and gas two-phase flow, which is complicated and limited. Therefore, a reasonable productivity formula of condensate gas reservoir with producing water is needed. The three-zone model of condensate gas reservoirs is generally applied to the physical model for inferring productivity. On this basis, an improved model is established, which includes that different seepage characteristics are considered for different zones. Moreover, the effects of inclined angle and water production on gas wells are regarded as pseudo-skin factors and additional-skin factors. In addition, Zone I considers the effects of high-speed nonDarcy effect(HSND), starting pressure gradient, stress sensitivity, inclined angle and water production; Zone II is the same way excepting starting pressure gradient and stress sensitivity ; Zone III only considers the effects of inclined angle and water production. As a result, a productivity equation with multiple factors for condensate gas wells is established. Through analysing cases and influences in H gas reservoir X1 well, the HSND, starting pressure gradient, stress sensitivity and water production have a negative impact on gas well productivity, but the inclined angle is opposite. Founded that the starting pressure gradient impacts on productivity is less than the HSND because of the limited radius of Zone I; the impact of the HSND on productivity increases with the decreasing of bottom hole pressure; the impact of water production on gas well productivity is much higher. When the angle is over 60°, the effect of gas
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Mugisho Joel Bacirheba, Tanoh Boguy Eddy Martial, Mirsamiev Narzullo Abdugaforovich, and Madumarov Mukhriddin Mukhammadjon Ugli. "Time Estimation of Gas-Water Contact Lift using Response Surface Analysis in Yamburg Gas Field Conditions." Journal of Advanced Research in Applied Sciences and Engineering Technology 22, no. 1 (January 16, 2021): 46–53. http://dx.doi.org/10.37934/araset.22.1.4653.
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The Yamburg oil and gas condensate field, like many northwestern fields, is at the final stage of production. The consequence is that the large amount of formation water in the inflow may accumulate in particular in well bottom hole. The response surface analysis is used as a new technique for gaining detailed understanding of the relationships between combinations of two predictor variables and a result variable. This approach was applied to the Yamburg field in order to estimate the time of gas-water contact lift considering the lithological characteristics of the reservoirs. The results of the predicted gas-water contact time were compared to the expected gas-water contact time, the data of which were considered for the study. Using the parameters of the model as well as the three-dimensional response surface, which was built to facilitate and improve the interpretation of the results, it was possible to predict the gas-water contact time under certain conditions.
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Koch, Jens-Ole, Andreas Frischbutter, Kjell Øygard, and John Cater. "The 35/9-7 Skarfjell discovery: a genuine stratigraphic trap, NE North Sea, Norway." Geological Society, London, Petroleum Geology Conference series 8, no. 1 (March 17, 2017): 339–54. http://dx.doi.org/10.1144/pgc8.34.
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AbstractThe Skarfjell oil and gas discovery, situated 50 km north of the Troll Field in the NE North Sea, was discovered by well 35/9-7 and was appraised by three additional wells operated by Wintershall, in the period 2012–14.The Skarfjell discovery is an example of a combined structural/stratigraphic trap. The trap formed along the northern edge of a deep WNW–ESE-trending submarine canyon, which was created by Volgian erosion of intra-Heather, Oxfordian-aged sandstones and then infilled with Draupne Formation shales. This mud-filled canyon forms the top and side seal, with the bottom seal provided by Heather shales. The reservoir comprises mid-Oxfordian deep-water turbidites and sediment gravity flows, which formed in response to tectonic hinterland uplift and erosion of the basin margin, 10–20 km to the east.The Skarfjell discovery contains light oil and gas, and may be subdivided into Skarfjell West, in which the main oil reservoir and gas cap have known contacts, and Skarfjell Southeast, which comprises thinner oil and gas reservoirs with slightly lower pressure and unknown hydrocarbon contacts.The Upper Jurassic Draupne and Heather formations are excellent source rocks in the study area. They have generated large volumes of oil and gas reservoired in fields, and discoveries for which the dominant source rock and its maturity have been established by oil to source rock correlation and geochemical biomarker analysis. The Skarfjell fluids were expelled from mid-mature oil source rocks of mixed Heather and Draupne Formation origin.The recoverable resources are estimated at between 9 and 16 million standard cubic metres (Sm3) of recoverable oil and condensate, and 4–6 billion Sm3 of recoverable gas. The Skarfjell discovery is currently in the pre-development phase and is expected to come on stream in 2021.
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Mugisho Joel Bacirheba, Tanoh Boguy Eddy Martial, Mirsamiev Narzullo Abdugaforovich, and Madumarov Mukhriddin Mukhammadjon Ugli. "Using Response Surface Analysis to Estimate Time of The Gas-Water Contact Lift in Yamburg Gas Field Conditions." Journal of Advanced Research in Fluid Mechanics and Thermal Sciences 87, no. 3 (October 6, 2021): 105–12. http://dx.doi.org/10.37934/arfmts.87.3.105112.
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Like many of the fields in northwest Siberia, the Yamburg oil and gas condensate field is in the final production stages. This, therefore, results in an accumulation of a large amount of formation water in the inflow at the bottom of the well. Response surface analysis is used as a new technique to gain a detailed understanding of the relationships between combinations of two predictor variables and an outcome variable. This approach was applied to the Yamburg field to estimate the time of the gas-water contact, considered as the result variable, by taking into account two groups of predictive variables which correspond to the reservoirs grouped by their lithological characteristics. The results of the predicted gas-water contact time were compared to the expected gas-water contact time, the data of which were taken into account for the study. Using the model parameters as well as the three-dimensional response surface, which was constructed to facilitate and improve the interpretation of the results, it was then possible to predict the gas-water contact time under certain conditions.
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Sun, Minwei, Khosrow Naderi, and Abbas Firoozabadi. "Effect of Crystal Modifiers and Dispersants on Paraffin-Wax Particles in Petroleum Fluids." SPE Journal 24, no. 01 (September 10, 2018): 32–43. http://dx.doi.org/10.2118/191365-pa.
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Summary Petroleum fluids from shale light-oil and gas/condensate reservoirs generally have a high content of normal paraffins. Paraffin-wax deposition is among the challenges in shale gas and oil production and in offshore flow assurance. Low-dosage chemical additives can be effective in paraffin-wax mitigation because of their high efficiency and economics. These additives are divided into broad categories of crystal modifiers and dispersants with vastly different molecular structures and mechanisms in wax-crystal-particle stabilization and wetting. This investigation focuses on the understanding of the differences in the aggregate size and morphology of chemical additives, and it centers on (1) wax-particle sedimentation from diluted petroleum fluids in vial tests, (2) wax-crystal-particle-size distributions and morphology by dynamic light scattering (DLS) and polarized-light microscopy, and (3) the wetting state from the effect of water. In two of the three petroleum-fluid samples used in this work, there is no visible precipitation at the bottom of the vials at temperatures below the wax-appearance temperature (WAT). The microscopic image of fluids along the length of the tube shows that the wax-particle size and intensity increase from top to bottom. To observe precipitation, we dilute the crude with a hydrocarbon such as n-heptane. The sedimentation of wax is then observed. The petroleum fluids used in this work have very low asphaltene content, and there is no complication from asphaltene precipitation. Our study shows that a small amount of crystal modifier and dispersant can reduce crystal-particle size to the submicron scale, and change the crystal morphology. We investigate the differences in the mechanisms of dispersants and crystal modifiers in bulk. Water, which is often coproduced with petroleum fluids, can increase the effectiveness of dispersants significantly by altering the wetting state of the wax-particle surface. Such enhancement is not found in crystal modifiers. Both additives affect the rheology of petroleum fluids.
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Biu, Victor Torkiowei, and Shi-Yi Zheng. "A New Approach in Pressure Transient Analysis: Using Numerical Density Derivatives to Improve Diagnosis of Flow Regimes and Estimation of Reservoir Properties for Multiple Phase Flow." Journal of Petroleum Engineering 2015 (July 12, 2015): 1–16. http://dx.doi.org/10.1155/2015/214084.
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This paper presents the numerical density derivative approach (another phase of numerical welltesting) in which each fluid’s densities around the wellbore are measured and used to generate pressure equivalent for each phase using simplified pressure-density correlation, as well as new statistical derivative methods to determine each fluid phase’s permeabilities, and the average effective permeability for the system with a new empirical model. Also density related radial flow equations for each fluid phase are derived and semilog specialised plot of density versus Horner time is used to estimate k relative to each phase. Results from 2 examples of oil and gas condensate reservoirs show that the derivatives of the fluid phase pressure-densities equivalent display the same wellbore and reservoir fingerprint as the conventional bottom-hole pressure BPR method. It also indicates that the average effective kave ranges between 43 and 57 mD for scenarios (a) to (d) in Example 1.0 and 404 mD for scenarios (a) to (b) in Example 2.0 using the new fluid phase empirical model for K estimation. This is within the k value used in the simulation model and likewise that estimated from the conventional BPR method. Results also discovered that in all six scenarios investigated, the heavier fluid such as water and the weighted average pressure-density equivalent of all fluid gives exact effective k as the conventional BPR method. This approach provides an estimate of the possible fluid phase permeabilities and the % of each phase contribution to flow at a given point. Hence, at several dp' stabilisation points, the relative k can be generated.
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Nasrabadi, Hadi, Kassem Ghorayeb, and Abbas Firoozabadi. "Two-Phase Multicomponent Diffusion and Convection for Reservoir Initialization." SPE Reservoir Evaluation & Engineering 9, no. 05 (October 1, 2006): 530–42. http://dx.doi.org/10.2118/66365-pa.
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Summary We present formulation and numerical solution of two-phase multicomponent diffusion and natural convection in porous media. Thermal diffusion, pressure diffusion, and molecular diffusion are included in the diffusion expression from thermodynamics of irreversible processes. The formulation and the numerical solution are used to perform initialization in a 2D cross section. We use both homogeneous and layered media without and with anisotropy in our calculations. Numerical examples for a binary mixture of C1/C3 and a multicomponent reservoir fluid are presented. Results show a strong effect of natural convection in species distribution. Results also show that there are at least two main rotating cells at steady state: one in the gas cap, and one in the oil column. Introduction Proper initialization is an important aspect of reliable reservoir simulations. The use of the Gibbs segregation condition generally cannot provide reliable initialization in hydrocarbon reservoirs. This is caused, in part, by the effect of thermal diffusion (caused by the geothermal temperature gradient), which cannot be neglected in some cases; thermal diffusion might be the main phenomenon affecting compositional variation in hydrocarbon reservoirs, especially for near-critical gas/condensate reservoirs (Ghorayeb et al. 2003). Generally, temperature increases with increasing burial depth because heat flows from the Earth's interior toward the surface. The temperature profile, or geothermal gradient, is related to the thermal conductivity of a body of rock and the heat flux. Thermal conductivity is not necessarily uniform because it depends on the mineralogical composition of the rock, the porosity, and the presence of water or gas. Therefore, differences in thermal conductivity between adjacent lithologies can result in a horizontal temperature gradient. Horizontal temperature gradients in some offshore fields can be observed because of a constant water temperature (approximately 4°C) in different depths in the seabed floor. The horizontal temperature gradient causes natural convection that might have a significant effect on species distribution (Firoozabadi 1999). The combined effects of diffusion (pressure, thermal, and molecular) and natural convection on compositional variation in multicomponent mixtures in porous media have been investigated for single-phase systems (Riley and Firoozabadi 1998; Ghorayeb and Firoozabadi 2000a).The results from these references show the importance of natural convection, which, in some cases, overrides diffusion and results in a uniform composition. Natural convection also can result in increased horizontal compositional variation, an effect similar to that in a thermogravitational column (Ghorayeb and Firoozabadi 2001; Nasrabadi et al. 2006). The combined effect of convection and diffusion on species separation has been the subject of many experimental studies. Separation in a thermogravitational column with both effects has been measured widely (Schott 1973; Costeseque 1982; El Mataaoui 1986). The thermogravitational column consists of two isothermal vertical plates with different temperatures separated by a narrow space. The space can be either without a porous medium or filled with a porous medium. The thermal diffusion, in a binary mixture, causes one component to segregate to the hot plate and the other to the cold plate. Because of the density gradient caused by temperature and concentration gradients, convection flow occurs and creates a concentration difference between the top and bottom of the column. Analytical and numerical models have been presented to analyze the experimental results (Lorenz and Emery 1959; Jamet et al. 1992; Nasrabadi et al. 2006). The experimental and theoretical studies show that the composition difference between the top and bottom of the column increases with permeability until an optimum permeability is reached. Then, the composition difference declines as permeability increases. The process in a thermogravitational column shows the significance of the convection from a horizontal temperature gradient.
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Zhang, Lei, and Guo Ming Liu. "Analysis Development Status of A12 Reservoir." Advanced Materials Research 650 (January 2013): 664–66. http://dx.doi.org/10.4028/www.scientific.net/amr.650.664.
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A12 oil and gas reservoirs in L Oilfield Carboniferous carbonate rocks of oil and gas bearing system, saturated with the gas cap and edge water and bottom water reservoir. The A12 oil and gas reservoir structure the relief of the dome-shaped anticline, oil, gas and water distribution controlled by structure, the gas interface -2785 meters above sea level, the oil-water interface altitude range -2940 ~-2980m, average-2960m. Average reservoir thickness of 23m, with a certain amount of dissolved gas drive and gas cap gas drive energy, but not very active edge and bottom water, gas cap drive index.
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Wojtanowicz, Andrew K., and Miguel Armenta. "Assessment of Down-Hole Water Sink Technology for Controlling Water Inflow at Petroleum Wells." Journal of Energy Resources Technology 126, no. 4 (December 1, 2004): 334–41. http://dx.doi.org/10.1115/1.1831282.
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Water inflow to petroleum wells hampers production of oil or gas leading to early shut downs of the wells without sufficient recovery of hydrocarbons in place. Downhole water sink (DWS) is a completion/production technique for producing water-free hydrocarbons with minimum amount of water from reservoirs with bottom water drive and strong tendency to water coning. DWS eliminates water invasion to hydrocarbon production by employing hydrodynamic mechanism of coning control in situ at the oil-water or gas-water contact. The mechanism is based upon a localized water drainage generated by another well completion (downhole water sink) installed in the aquifer beneath the oil/water or gas/water contact. The paper summarizes the development and state-of-the-art of DWS technology. Presented are results from theoretical studies, physical and numerical experiments, and field projects to date. It is demonstrated that DWS could increase recovery and control water production in vertical and horizontal oil wells—with natural flow, downhole pumps or gas lift, and in the gas wells producing from low-pressure tight gas reservoirs. To date, DWS has been used in reservoirs with bottom water. Moreover, in principle, the technology might also be used in the dipping reservoir structures with encroaching side-water.
Dissertations / Theses on the topic "Bottom water-drive oil and gas condensate reservoirs"
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Серженьга, О. В. "Науково-методичні засади оцінки характеру насичення пластів і положення газонафтового контакту з використанням геоелектричної моделі присвердловинної зони (на прикладі нафтогазоконденсатних родовищ Західно-Сибірської нафогазоносної провінції)." Thesis, Івано-Франківський національний технічний університет нафти і газу, 2007. http://elar.nung.edu.ua/handle/123456789/4219.
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У дисертації висвітлюються актуальні питання визначення положення газонафтового і водонафтового контактів на “водоплавних” нафтогазоконденсатних покладах за результатами геофізичних досліджень у відкритому стовбурі свердловини. Такі поклади є об'єктами з дуже складними електричними властивостями присвердловинної зони і потребують підвищення інформативності комплексу методів ГДС. Теоретично обґрунтовано і доведено фактичними дослідженнями в свердловинах переваги методу ВІКІЗ для визначення параметрів геоелектричної моделі порід-колекторів, які виповнюють теригенні відклади юрського комплексу ЗСНГП. Методологічні властивості методу зумовлюють достовірнішу оцінку геоелектричних параметрів зони проникнення і дають можливість виявити облямовуючу зону. На базі геофізичної інформації під час дослідження розрізу свердловин та інформації по визначенню фізико-хімічних властивостей пластового флюїду, створено фізико-геологічну модель присвердловинної зони, яка характеризує залежність електричних параметрів присвердловинної зони від геологічних властивостей порід-колекторів з різним типом пластового флюїду. Свердловинні дослідження методом ВІКІЗ на Кинському і Харампурському нафтогазоконденсатних родовищах показують що зміна параметрів геоелектричного розрізу свердловини відбувається під час проходження свердловиною через ГНК і ВНК. Створена фізико-геологічна модель присвердловинної зони для «водоплавних» нафтогазоконденсатних покладів має можливість не тільки виділяти інтервал продуктивних колекторів, але і розділяти їх на нафтонасичені і газонасичені. Запропонована уніфікована схема використання порівняння газонасичених інтервалів, виділених за методом ВІКІЗ і способом ПНК, яка дає можливість визначити положення ГНК як на етапі оперативного висновку, так і на етапі побудови флюїдальної моделі покладу.В диссертации освещаются актуальные вопросы определения положения газонефтяного и водонефтяного контактов на «водоплавающих» нефтегазоконденсатных залежах по результатам геофизических исследований в открытом стволе скважины. Такие залежи являются объектами с очень сложными электрическими свойствами прискважинной зоны и требуют повышения информативности комплекса методов ГИС. Теоретически обосновано и доказано на практических исследованиях преимущество метода ВИКИЗ при определении параметров геоэлектрической модели пород-коллекторов, которые составляют терригенные отложения юрского комплекса ЗСНГП. Методологические свойства метода обеспечивают более однозначную оценку геоэлектрических параметров зоны проникновения и дают возможность выявлять окаймляющую зону. На базе геофизической информации по исследованиям разрезов скважин и информации по определению физико-химических свойств пластового флюида, создано физикогеологическую модель прискважинной зоны, которая характеризует зависимость электрических параметров прискважинной зоны от геологических свойств пород-коллекторов с разным типом пластового флюида. Доказано, что в течении первых 5-10 часов после раскрытия разреза по электрическим параметрам техногенных неоднородностей с высоким уровнем достоверности можно определить тип насыщающего пластового флюида. Скважинные исследования методом ВИКИЗ на Кынском и Харампурском нефтегазоконденсатных месторождениях показывают, что изменение параметров геоэлектрического разреза скважины происходит при прохождении скважиной через ГНК и ВНК. Предложено унифицированную схему использования соответствия газонасыщенных интервалов, выделенных по методу ВИКИЗ и методике ПИК, которая дает возможность определять положение ПНК как на этапе оперативного заключения, так и на этапе построения флюидальной модели залежи.
The Theses illustrates relevant issues of gas-oil and oil-water contacts position location in bottom water-drive oil-gas condensate reservoirs, belonging to laminated deposits of Jurassic bedrock in West-Siberian petroleum province. Such deposits are objects with very complicated electrical properties of the well bore zone, abruptly changing with the deposit’s height. Investigation of deposits with multicomponent reservoir fluid composition requires implementation of new geophysical wells survey methods and increase of useful information volume, extractable from the carried out complex of geographical information system (GIS). As a result of the author’s investigations, a number of scientific conclusions were drawn, which represent great practical importance in the field of geophysical survey of oil and gas wells and geological simulation for deposit fluidic structures with multicomponent composition of reservoir fluid. Advantages of the VIKIZ method for surveying lamellar terrigenous deposits of West-Siberian petroleum province of Jurassic horizon have been theoretically validated and proved in practice. Based on geophysical information and the information on formation fluid property investigations, main points and directions for a physical and geological model were formulated. The model characterizes relation between the penetration zone parameters and geological properties of reservoirs with different types of fluids. A method was developed which allows locating the OWC based on the parameters of the penetration zone and the low-resistivity zone. This can be important information for of specification standard oil-water surface interpretation results. A physical and geological model was created which allows discriminating oil-saturated reservoirs in the pay zone from gas-saturated ones and determines OWC position in bottom water-drive oil and gas condensate reservoirs of West-Siberian petroleum province. A unified scheme for gas-saturated formation comparison usage was suggested. The intervals were distinguished based on the VIKIZ method and PNK technique, which allowed determining GOC position at the operative conclusion stage, as well as at the stage of fluidic model deposit creation.
Book chapters on the topic "Bottom water-drive oil and gas condensate reservoirs"
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Zhu, Weiyao, Xiaohe Huang, and Ming Yue. "A Modified Calculation Method for the Water Coning Simulation Mode in Oil Reservoirs with Bottom Water Drive." In Gas Injection for Disposal and Enhanced Recovery, 331–37. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2014. http://dx.doi.org/10.1002/9781118938607.ch19.
Full textConference papers on the topic "Bottom water-drive oil and gas condensate reservoirs"
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Tang, Xueqing, Ruifeng Wang, Zhongliang Cheng, and Hui Lu. "Rich-Gas Condensate Huff and Puff Process in High-Volume, Watered-Out, and Highly Viscous Heavy Oil Wells, Case Study in Iraq." In SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205742-ms.
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Abstract Halfaya field in Iraq contains multiple vertically stacked oil and gas accumulations. The major oil horizons at depth of over 10,000 ft are under primary development. The main technical challenges include downdip heavy oil wells (as low as 14.56 °API) became watered-out and ceased flow due to depleted formation pressure. Heavy crude, with surface viscosities of above 10,000 cp, was too viscous to lift inefficiently. The operator applied high-pressure rich-gas/condensate to re-pressurize the dead wells and resumed production. The technical highlights are below: Laboratory studies confirmed that after condensate (45-52ºAPI) mixed with heavy oil, blended oil viscosity can cut by up to 90%; foamy oil formed to ease its flow to the surface during huff-n-puff process.In-situ gas/condensate injection and gas/condensate-lift can be applied in oil wells penetrating both upper high-pressure rich-gas/condensate zones and lower oil zones. High-pressure gas/condensate injected the oil zone, soaked, and then oil flowed from the annulus to allow large-volume well stream flow with minimal pressure drop. Gas/condensate from upper zones can lift the well stream, without additional artificial lift installation.Injection pressure and gas/condensate rate were optimized through optimal perforation interval and shot density to develop more condensate, e.g. initial condensate rate of 1,000 BOPD, for dilution of heavy oil.For multilateral wells, with several drain holes placed toward the bottom of producing interval, operating under gravity drainage or water coning, if longer injection and soaking process (e.g., 2 to 4 weeks), is adopted to broaden the diluted zone in heavy oil horizon, then additional recovery under better gravity-stabilized vertical (downward) drive and limited water coning can be achieved. Field data illustrate that this process can revive the dead wells, well production achieved approximately 3,000 BOPD under flowing wellhead pressure of 800 to 900 psig, with oil gain of over 3-fold compared with previous oil rate; water cut reduction from 30% to zero; better blended oil quality handled to medium crude; and saving artificial-lift cost. This process may be widely applied in the similar hydrocarbon reservoirs as a cost-effective technology in Middle East.
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Fathalla, Magdy Farouk, Mariam Ahmed Al Hosani, Ihab Nabil Mohamed, Ahmed Mohamed Al Bairaq, Aditya Ojha, Salman Akram Mengal, Yuni Budi Pramudyo, Ramanathan Nachiappan, and Ibukun Olatunbosun Bankole. "Maximizing Recovery from a Depleted Oil Rim Carbonate Reservoir Through an Integrated FDP Approach: Case Study Onshore Field Abu Dhabi, UAE." In Abu Dhabi International Petroleum Exhibition & Conference. SPE, 2021. http://dx.doi.org/10.2118/207313-ms.
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Abstract This paper examines risk and rewards of co-development of giant reservoir has gas cap concurrently produce with oil rim. The study focus mainly on the subsurface aspects of developing the oil rim with gas cap and impact recoveries on both the oil rim and gas cap. The primary objective of the project was to propose options to develop oil rims and gas cap reservoir aiming to maximize the recovery while ensuring that the gas and condensate production to the network are not jeopardized and the existing facility constraints are accounted. Below are the specific project objectives for each of the reservoirs: To evaluate the heterogeneities of the reservoir using available surveillance information data.To evaluate the reservoir physics and define the depleted oil rims current Gas oil contact and Water Oil Contact using the available surveillance information and plan mitigate reservoir management plan.To propose strategies in co-development plan with increase in oil rim recovery without impact on gas cap recovery.To propose the optimum Artificial methods to extended wells life by minimize the drawn down and reduce bottom head pressure.To propose methods to reduce the well head pressure to reduce back pressure on the wells. The methodology adopted in this study is based on the existing full field compositional reservoir simulation model for proposing different strategical co-development scenario: Auto gas lift Pilot implementation phase.Reactivate using Auto gas lift all the in-active wells.Propose the optimum wells drilling and completion design, like MRC, ERD and using ICV to control water and gas breakthrough.Proposing different field oil production plateauPropose different water injection scheme The study preliminary findings that extended reach drilling (ERD) wells were proposed, The ability to control gas and water breakthrough along the production section will be handled very well by deploying the advanced flow control valves, reactivation of existing Oil rim wells with Artificial lift increases Oil Rim recovery factor, and optimize offtake of gas cap and oil rim is crucial for increase the recovery factories of oil Rim and gas cap.
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Paduchak, Mykhaylo, Viktor Dudzych, and Anatolii Boiko. "Minimization of Negative Impact of Well Cementing on Productive Horizons by Utilization of Swellable Packers." In SPE Eastern Europe Subsurface Conference. SPE, 2021. http://dx.doi.org/10.2118/208510-ms.
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Abstract Avoiding of negative impact of slurry contact with productive sections by utilization of swellable pakers well completion systems as a key solution for depleted reservoirs. Results are compared to previously used classic well completion method with production casing cementing The new method of the well completion is based on a long period and many wells operations within Svyrydivske field in Dnipro-Donets Basin (here and after DDB). Precise selection of hybrid, oil and water based elastomers and correct placement in the appropriate hole zones for water and sectional isolation together with oil based mud utilization during drilling have provided stable production in depleted reservoirs and have minimized negative consequences from water filtration. The results achieved and the well completion method are described in detail to allow readers to replicate all results in a comparable geological conditions in DDB. Current well completion method has a couple of outstanding results achieved: – well integrity barrier is based on sufficient differential pressure provided by swellable packers; – reliable long term water isolation of all detected water contained intervals; – the production sections are not polluted by slurry filtrated water; – increased production rate comparing to cemented wells; – no risks of slurry loss during well cementing. This technology has been successfully implemented in both vertical and deviated wells on 4.5″ (114.3 mm) casing OD, in the interval 5100-5450 meters, bottom hole temperature 120-135°C. The differential pressure provided by swellable packer is up to 10,000 PSI (68.9 MPa). Fluid reactive packers are ready to expand and isolate highly cavernous hole sections and keep differential pressure sustainably. To achieve the best results with this well completion method, it is also important to use reliable gas tight casing connections and know precise reservoir characteristics. That is why the technology is recommended to be customized for well known brownfield reservoirs with high rate of depletion. The main benefit of the well completion method is a proved and safe technical solution for mainly depleted deep gas and condensate deposits in DDB (Ukraine) with sensitive economics
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Ogbunude, Basil, Aniekan Obot, Abdul-Wahab Sa'ad, Sunday Maxwell-Amgbaduba, Etta Agbor, Maryam Tafida, Onyedikachi Okereke, Jonathan Mude, and Oforiokuma Gogo. "Integrated Approach to Produced Water Disposal Management in a Brown Field: Safeguarding Production, Reducing Cost, Managing Deferment & Reducing HSSE Exposure." In SPE Nigeria Annual International Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/208235-ms.
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Abstract Often, the production of oil and gas from underground reservoirs is accompanied by produced water which generally increases with time for a matured field, attributable to natural water encroachment, bottom water ingress, coning effect due to higher production rates, channeling effects, etc. This trend poses a production challenge with respect to increased OPEX cost and environmental considerations of treatment/handling and disposal of the produced water considering the late life performance characterized by low reward margins. Hence, produced water management solutions that reduce OPEX cost is key to extending the field life whilst ensuring a positive cash flow for the asset. SK field is located in the Swamp Area of the Niger Delta, with a capacity of 1.1Bcf gas plant supplying gas to a nearby LNG plant. Oil and gas production from the field is evacuated via the liquid and gas trunk lines respectively. Due to the incessant tampering with oil delivery lines and environmental impact of spillage, the condensate is spiked through the gas trunk line to the LNG plant. Largely, the water/effluent contained in the tank is evacuated through the liquid line. Based on the availability of the liquid line (ca. 40%-60%), the produced water is a constraint to gas production with estimated tank endurance time (ca. 8 days at 500MMscfd). This leads to creaming of gas production and indeed gas deferments due to produced water management, making it difficult to meet the contractual supply obligation to the LNG plant. An interim solution adopted was to barge the produced water to the oil and gas export terminal, with an associated OPEX cost of ca. US$2Mln/month. Upon further review of an alternate barging option, this option was considered too expensive, inefficient and unsustainable with inherent HSSE exposure. Therefore, a produced water re-injection project was scoped and executed as a viable alternative to produced water management. This option was supported by the Regulators as a preferred option for produced water management for the industry.
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Al-Mudhafar, Watheq J. "Hybrid Process of Gas Injection and Downhole Water Sink - Assisted Gravity Drainage GDWS-AGD to Improve Oil Recovery in Reservoirs with Infinite Edge and/or Bottom Water Drive." In SPE Russian Petroleum Technology Conference. Society of Petroleum Engineers, 2018. http://dx.doi.org/10.2118/191624-18rptc-ms.
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Taghavi, Soheila, Haavard Aakre, and Britt M. E. Moldestad. "Performance Analysis of Autonomous Inflow Control Valve in a SAGD Late Life Process with Non-Condensable Gases." In SPE Canadian Energy Technology Conference. SPE, 2022. http://dx.doi.org/10.2118/208915-ms.
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Abstract The performance of an autonomous inflow control valve (AICV), used to restrict the inflow of unwanted fluids like gas and/or steam was simulated using an industrial reservoir simulator. The simulation results were used to determine how AICVs can improve the oil recovery in steam assisted gravity drainage (SAGD) operations. Utilizing inflow or flow control devices (ICDs/FCDs) in SAGD wells is a method with promising results. FCDs delay steam breakthrough and increase the oil recovery. The recently developed technology, AICV, further improves the oil recovery from SAGD operations. This paper provides a summary of the test data acquired from the full-scale flow loop testing that replicates the downhole operating conditions. Single and multiphase flow performance of an orifice type ICD and AICV is presented and compared. The results confirm the ability of the AICV to restrict the production of gas and/or steam. A performance analysis based on the results from the experiments and well case simulations is presented. The paper also presents an innovative approach on analyzing the well conditions which brings an insight into SAGD production wells completed with AICVs. Simulations are performed in different scenarios of a SAGD late life process with non-condensable gases (NCGs), and these results confirmed a significant reduction in the gas liquid ratio (GLR), and an increased oil production when using AICV compared to the open hole case. Simulation results demonstrated that utilizing AICV in the SAGD production wells will reduce the gas and steam production by 64%. The reduction of steam production from the breakthrough zones allows a lower bottom hole pressure. This gives a higher sandface drawdown in the zones with less mobile oil, and thus a higher production from these zones. Further, this forces the steam chamber to be more evenly distributed along the different zones, resulting in increased oil recovery. Considering the environmental aspect, AICV can contribute to a considerable reduction in the steam use which will consequently reduce the energy and water usage for steam generation. As a result, utilizing AICV in SAGD operations will improve the economics of SAGD projects.
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Schrynemeeckers, Rick. "Acquire Ocean Bottom Seismic Data and Time-Lapse Geochemistry Data Simultaneously to Identify Compartmentalization and Map Hydrocarbon Movement." In Offshore Technology Conference. OTC, 2021. http://dx.doi.org/10.4043/30975-ms.
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Abstract Current offshore hydrocarbon detection methods employ vessels to collect cores along transects over structures defined by seismic imaging which are then analyzed by standard geochemical methods. Due to the cost of core collection, the sample density over these structures is often insufficient to map hydrocarbon accumulation boundaries. Traditional offshore geochemical methods cannot define reservoir sweet spots (i.e. areas of enhanced porosity, pressure, or net pay thickness) or measure light oil or gas condensate in the C7 – C15 carbon range. Thus, conventional geochemical methods are limited in their ability to help optimize offshore field development production. The capability to attach ultrasensitive geochemical modules to Ocean Bottom Seismic (OBS) nodes provides a new capability to the industry which allows these modules to be deployed in very dense grid patterns that provide extensive coverage both on structure and off structure. Thus, both high resolution seismic data and high-resolution hydrocarbon data can be captured simultaneously. Field trials were performed in offshore Ghana. The trial was not intended to duplicate normal field operations, but rather provide a pilot study to assess the viability of passive hydrocarbon modules to function properly in real world conditions in deep waters at elevated pressures. Water depth for the pilot survey ranged from 1500 – 1700 meters. Positive thermogenic signatures were detected in the Gabon samples. A baseline (i.e. non-thermogenic) signature was also detected. The results indicated the positive signatures were thermogenic and could easily be differentiated from baseline or non-thermogenic signatures. The ability to deploy geochemical modules with OBS nodes for reoccurring surveys in repetitive locations provides the ability to map the movement of hydrocarbons over time as well as discern depletion affects (i.e. time lapse geochemistry). The combined technologies will also be able to: Identify compartmentalization, maximize production and profitability by mapping reservoir sweet spots (i.e. areas of higher porosity, pressure, & hydrocarbon richness), rank prospects, reduce risk by identifying poor prospectivity areas, accurately map hydrocarbon charge in pre-salt sequences, augment seismic data in highly thrusted and faulted areas.
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Abdulmageed, Mohamed, Aly Elkordy, and Maria Vazquez. "Practical Solution for Rigless Water Shut off Without Using Thru- Tubing Bridge Plug in offshore Gas Lift Well, GUPCO - Egypt." In SPE Conference at Oman Petroleum & Energy Show. SPE, 2022. http://dx.doi.org/10.2118/200043-ms.
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Abstract The Gulf of Suez Petroleum Company (GUPCO) is one of the main production Companies in Egypt. Most of production rate in GUPCO is dependent on gas lift method for lifting reservoir fluid to the surface. Many reservoirs in Gulf of Suez are depletion (solution gas drive); so GUPCO injects about 150,000 BWPD to compensate reservoir pressure, and GUPCO has several active water drive reservoirs which water increasing comes from bottom intervals in some cases. As the water cut increases in the well, water shut off (WSO) is required; based on production logging tool (PLT) data, to avoid water loading (backpressure on formation), allow low quality sand/ intervals to share in production, avoid corrosion of wellbore tubing, and scale build up in the tubing which may cost a lot of money for cleaning. In general, GUPCO uses thru-tubing bridge plug (TTBP) and capping it with sufficient length of cement column for rigless WSO. As all fields of GUPCO are offshore; so WSO and other jobs are costly in comparison to onshore fields. Based on this, any cost saving, innovation, or idea lead to maximize output in safe manner (e.g. increasing well production oil) is highly appreciated and recommended for execution. Water shutoff techniques are either mechanical methods or chemical methods. These methods can be used individually or together in one job. Mechanical methods are usually used in wellbore WSO, and chemical methods are used in near wellbore (NWB) for plugging perm zones or restricting water flow as relative permeability modifier (RPM) chemical. Water shut off selection depends on many factors as well deviation, well completion type, and others that should be taken in consideration. This paper details some of the challenges associated with performing conventional WSO using electric-line and how to overcome these challenges. For our interested case, there is no common thru-tubing bridge plug (TTBP) in the market can be set in 9 5/8" and pass through minimum tubing restriction (XN- nipple 2.63" ID). Therefore, the well was planned to perform WSO using CTU with high cost, which is low priority for the time being. The practical WSO method provides solution for these challenges with low cost, and high percentage of success.
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Buwauqi, Salim, Ali Al Jumah, Abdulhameed Shabibi, Ameera Harrasi, Mahmoud Abd El-Fattah, Tejas Kalyani, and Ahmed Fahmy. "Case Study: How the Newest Generation of Autonomous Inflow Control Device Helps to Control Excessive Wells Water Production within a Major Sultanate of Oman Oilfield." In Offshore Technology Conference Asia. OTC, 2022. http://dx.doi.org/10.4043/31483-ms.
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Abstract The field is located in the south of Sultanate of Oman and was discovered in 1980 The field produces from sandstone reservoirs a heavy crude with high viscosity (up to 2000 cP) value that contains no appreciable solution gas. Production is supported by a bottom active water drive aquifer. An unfavourable mobility contrast between the oil and formation water results in rapid water breakthrough and a large portion of a well's reserves are produced at high water cuts. The average economic limit of wells in the field is about 98% water cut. Thus, water management plays a key role in well economics. The new horizontal producer wells target is to drain by-passed oil with only 30 ~ 80 m spacing. Injectors are at the flank and are injecting deep into the aquifer. Water breakthrough occurs at high sand permeability and once happened; water will dominate well production due to unfavourable mobility ratio. Some of the new producer wells are completed with Wire-Wrapped Screen (WWS) – Stand Alone Screen, and swellable packers to isolate higher water-saturated zones. However, most of these wells start typically with a 60% water cut (BSW) or more and rapidly reach +90%. To overcome current reservoir/production challenges; The operator has used the latest Autonomous Inflow Control Device (AICD) Technology called Autonomous Inflow Control Valves (AICV). ICD's and previous generation Autonomous Inflow Control Devices (AICD) has shown in many cases increased oil production and higher recovery with better fluid influx balance along the well. However, neither ICD nor AICD can shut off the water production completely without well intervention. The AICV can restrict unwanted water significantly and autonomously. The AICV are based on different flow behaviour for laminar and turbulent flow that is utilized in a pilot flow to actuate a piston position to restrict unwanted fluids. The design with two parallel flow paths ensures the AICV is open for oil, and close for water autonomously. The AICV technology is based on Hagen-Poiseuille and Bernoulli's principles and is truly autonomous as it can identify the fluid flowing through it based on fluid properties such as viscosity, density and flowrate. For unwanted fluid such as water and Gas, AICV can generate enough force that will shut off the device if required. This makes it more robust than any other commercially available AICDs. AICV effect is reversible i.e. when the saturation of unwanted fluid (Sg or Sw) around the wellbore reduces, AICV will re-open for the oil production, thus draining all possible oil around the wellbore. In this paper, AICV performance will be discussed and comparative analysis with production performance of wells completed with WWS completed in the same reservoir will be presented. Based on the regular well testing and production analysis, it is evident that AICV technology has helped the operator in managing/shutting off the unwanted water production autonomously. This new AICV technology has the core application principles of ICD completions but the additional benefit of improved control/complete water shut-off without intervention; zero cost water shut-off operation and helps drain by-passed oil and thus maximizes recovery factors.