Academic literature on the topic 'Geology|Petroleum geology|Petroleum engineering'

The Spraberry Formation is a Leonardian age submarine fan deposit restricted to the Midland Basin. The formation consists of very fine-grained sandstone, medium to coarse grain size siltstones, organic shales and carbonate mudstones. These rocks show variability in sedimentary structures and bedding types varied from thinly laminated to convolute laminations. Bioturbations were present in some samples and soft sediment deformation, such as water escape features, sediment loading and flame structures.

The Spraberry Formation is a naturally fractured reservoir with low porosity and low matrix permeability. Porosity measured varied from 2% in rocks with poor reservoir quality such as the argillaceous siltstone and mudstone while good reservoir rocks had an average porosity of 9%. Seven lithofacies were identified based on sedimentary structures, grain size and rock fabrics. Petrographic analysis showed four porosity types: (1) intragraular porosity; (2) dissolution porosity; (3) fracture porosity and (4) intergranular porosity. Fractured porosity was only observed in the argillaceous siltstone lithofacies.

The prominent diagenetic influences on the Spraberry Formation are: quartz cementation, quartz overgrowth, illtization of smectite, feldspar dissolution, clay precipitation, carbonate cementation, formation of framboidal pyrite and fracture formation. These diagenetic features were observed using scanning electron microscope (SEM) and in thin sections. Generally, petrophysical properties, such as porosity and permeability, vary gradually from reservoir rocks to non-reservoir rock. Observed trends where: 1) increasing organic and argillaceous content with decreasing porosity and 2) increasing carbonate sediments and calcite cements with decreasing porosity. Mineralogical analysis from FTIR showed an abundance of quartz and calcite, while illite is the prominent clay mineral observed in all samples.

The Pine Prairie Field is situated on a salt dome in northern Evangeline Parish, located in south-central Louisiana. Pine Prairie contains the only known Cook Mountain Formation hydrocarbon reservoir in Louisiana. Operators have targeted and produced hydrocarbons from the Cook Mountain reservoir in eight wells at the Pine Prairie Field. The source and origin of the Cook Mountain’s reservoir properties are unknown. The objective of this study is to determine the origin of the Cook Mountain Formation’s reservoir properties by identifying the processes associated with the formation of a Cook Mountain Reservoir. There are two carbonate outcrops at the surface expression of the Pine Prairie Dome. Samples were taken and thin sections made to determine the relationship, if any, to the Cook Mountain Formation. Thin section analysis of the carbonate outcrop was used to gain a better understanding of the depositional setting present at Pine Prairie Field. Well log, seismic, and production data were integrated to determine that, in all instances, commercial Cook Mountain production is associated with fault zones. The passage of acidic, diagenetic fluids through Cook Mountain fault zones generated areas of vuggy porosity proximal to Cook Mountain faulting. Further, fluctuations in short-term pressure gradients associated with salt diapirism resulted in the vertical migration of hydrocarbons via fault zones. In the Pine Prairie Field, fault seal breakdown occurs in Sparta and Wilcox Reservoirs, subsequently charging the Cook Mountain fault zone. Early hydrocarbon charge from the underlying Wilcox and Sparta Reservoirs prevented additional diagenesis, preserving secondary porosity in areas of Cook Mountain faulting.

This thesis describes the advantages of investigating gas shales reservoir description on a nanoscale by using petrographic analysis and core plug petrophysics to characterize the Barnett, Marcellus and Mancos shale plays. The results from this analysis now indicate their effects on the reservoir quality. Helium porosity measurements at confining pressure were carried out on core plugs from this shale plays. SEM (Scanning Electron Microscopy) imaging was done on freshly fractured gold-coated surfaces to indicate pore structure and grain sizes. Electron Dispersive X-ray Spectroscopy was done on freshly fractured carbon-coated surfaces to tell the mineralogy. Extra-thin sections were made to view pore spaces, natural fractures and grain distribution.

The results of this study show that confining pressure helium porosity values to be 9.6%, 5.3% and 1.7% in decreasing order for the samples from the Barnett, Mancos and Marcellus shale respectively. EDS X-ray spectroscopy indicates that the Barnett and Mancos have a high concentration of quartz (silica-content); while the Mancos and Marcellus contain calcite. Thin section analysis reveals obvious fractures in the Barnett, while Mancos and Marcellus have micro-fractures.

Based on porosity, petrographic analysis and mineralogy measurements on the all the samples, the Barnett shale seem to exhibit the best reservoir quality.

CO₂ flooding has proven to be an effective technique for enhanced oil recovery. However, the application of CO₂ flooding in the recovery process of asphaltenic crude systems is often avoided, as high asphaltene precipitation rates may occur. While the effects of asphaltene concetration and CO₂ injection pressure on asphaltene precipitation rate have been the focus of many studies, asphaltene precipitation rate is not a reliable factor to predict the magnitude of asphaltene-induced formation damage. Wettability alteration is only caused by the immobile asphaltene deposits on the rock surface. The enternmaint of flocs may occur at high fluid velocity. Morover, the effective permeability reduction is only caused by the flocs, which have become large enough to block the pore throats. The dissociation of the flocs may occur under certain flow conditions. In this study, a compositional reservoir simulation was conducted using Eclipse 300 to investigate the injection practice, which avoids asphaltene-induced formation damage during both immiscible and miscible CO₂ flooding in asphaltenic crude system. Without injection, at pressure above bubble point, slight precipitation occurred in the zone of the lowest pressure near the producing well. As pressure approached the bubble point, precipitation increased due to the change in the hydrocarbon composition, which suggested that the potential of asphaltene-induced formation damage is determined by the overall fluid composition. At very low pressure, precipitation decreased due to the increase in the density.

As CO₂ was injected below the minimum miscibility pressure, a slight precipitation occurred in the transition zone at the gas-oil interface due to the microscopic diffusion of the volatile hydrocarbon components caused by the local concentration gradients. The increase in CO₂ injection rate did not significantly increase the precipitation rate.

As CO₂ was injected at pressure above the minimum miscibility pressure, precipitation occurred throughout the entire reservoir due to the vaporizing drive miscibility process. While precipitation increased with the injection rate, further increase in the injection rate slightly decreased the deposition due to shear. The pressure drop in the water phase caused by the pore throat increased the local water velocity, resulting in a more effective removal of the clogging asphaltene material.

The objective of this study is threefold: 1) Build a dual-porosity, geological reservoir model of Niobrara formation in the Wishbone Section of the DJ Basin. 2) Use the geologic static model to construct a compositional model to assess performance of Well 1N in the Wishbone Section. 3) Compare the modeling results of this study with the result from an eleven-well modeling study (Ning, 2017) of the same formation which included the same well. The geologic model is based on discrete fracture network (DFN) model (Grechishnikova 2017) from an outcrop study of Niobrara formation.

This study is part of a broader program sponsored by Anadarko and conducted by the Reservoir Characterization Project (RCP) at Colorado School of Mines. The study area is the Wishbone Section (one square mile area), which has eleven horizontal producing wells with initial production dating back to September 2013. The project also includes a nine-component time-lapse seismic. The Wishbone section is a low-permeability faulted reservoir containing liquid-rich light hydrocarbons in the Niobrara chalk and Codell sandstone.

The geologic framework was built by Grechishnikova (2017) using seismic, microseismic, petrophysical suite, core and outcrop. I used Grechishnikova’s geologic framework and available petrophysical and core data to construct a 3D reservoir model. The 3D geologic model was used in the hydraulic fracture modeling software, GOHFER, to create a hydraulic fracture interpretation for the reservoir simulator and compared to the interpretation built by Alfataierge (2017). The reservoir numerical simulator incorporated PVT from a well within the section to create the compositional dual-porosity model in CMG with seven lumped components instead of the thirty-two individual components. History matching was completed for the numerical simulation, and rate transient analysis between field and actual production are compared; the results were similar. The history matching parameters are further compared to the input parameters, and Ning’s (2017) history matching parameters.

The study evaluated how fracture porosity and rock compaction impacts production. The fracture porosity is a major contributor to well production and the gas oil ratio. The fracture porosity is a major sink for gathering the matrix flow contribution. The compaction numerical simulations show oil production increases with compaction because of the increased compaction drive. As rock compaction increases, permeability and porosity decreases. How the numerical model software, CMG, builds the hydraulic fracture, artificially increases the original oil-in-place and decreases the recovery factor. Furthermore, grid structure impacts run-time and accuracy to the model. Finally, outcrop adds value to the subsurface model with careful qualitative sedimentology and structural extrapolations to the subsurface by providing understanding between the wellbore and seismic data scales.

In this study, imbibition experiments are used to explain the significant fluid loss, often more than 70%, of injected water during well stimulation and flowback in the context of natural gas production from shale formations. Samples from a 180 ft. long section of a vertical well were studied via spontaneous and forced imbibition experiments, at lab-scale, on small samples with characteristic dimensions of a few cm; in order to quantify the water imbibed by the complex multi-porosity shale system. The imbibition process is, typically, characterized by a distinct transition from an initial linear rate (vs. square root of time) to a much slower imbibition rate at later times. These observations along with contact angle measurements provide an insight into the wettability characteristics of the shale surface. Using these observations, together with an assumed geometry of the fracture system, has made it possible to estimate the distance travelled by the injected water into the formation at field scale.

Shale characterization experiments including permeability measurements, total organic carbon (TOC) analysis, pore size distribution (PSD) and contact angle measurements were also performed and were combined with XRD measurements in order to better understand the mass transfer properties of shale. The experimental permeabilities measured in the direction along the bedding plane (10 ^–1–10^–2 mD) and in the vertical direction (~10^–4 mD) are orders of magnitude higher than the matrix permeabilities of these shale sample (10^–5 to 10 ^–8 mD). This implies that the fastest flow in a formation is likely to occur in the horizontal direction, and indicates that the flow of fluids through the formation occurs predominantly through the fracture and micro-fracture network, and hence that these are the main conduits for gas recovery. The permeability differences among samples from various depths can be attributed to different organic matter content and mineralogical characteristics, likely attributed to varying depositional environments. The study of these properties can help ascertain the ideal depth for well placement and perforation.

Forced imbibition experiments have been carried out to better understand the phenomena that take place during well stimulation under realistic reservoir conditions. Imbibition experiments have been performed with real and simulated frac fluids, including deionized (DI) water, to establish a baseline, in order to study the impact on imbibition rates resulting from the presence of ions/additives in the imbibing fluid. Ion interactions with shales are studied using ion chromatography (IC) to ascertain their effect on imbibition induced porosity and permeability change of the samples. It has been found that divalent cations such as calcium and anions such as sulfates (for concentrations in excess of 600 ppm) can significantly reduce the permeability of the samples. It is concluded, therefore, that their presence in stimulating fluids can affect the capillarity and fluid flow after stimulation. We have also studied the impact of using fluoro-surfactant additives during spontaneous and forced imbibition experiments. A number of these additives have been shown to increase the measured contact angles of the shale samples and the fluid recovery from them, thus making them an ideal candidate for additives to use. Their interactions with the shale are further characterized using the Dynamic Light Scattering (DLS) technique in order to measure their hydrodynamic radius to compare it with the pore size of the shale sample.

To efficiently produce oil from unconventional reservoirs, it is imperative to determine and understand the geomechanical properties of the formation. But, due to the high cost of obtaining these properties from geomechanical well logs, businesses are looking for all possible ways to cut cost. The plummeting oil prices have been reflected in company spending and have driven companies to prioritize focusing attention on the rising production costs and venture all possible ways to reduce these costs. The real challenge is how to preserve these profitable gains? There is a need for an alternate and cost- effective way to obtain geomechanical properties of the rocks.

By utilizing Data Analytics, Data Mining, and ANN, patterns are observed between parameters from large amounts of data and, thus, important information regarding the formation can be understood. In this study, a relationship between conventional well logs and geomechanical well logs are established. Properties such as Young’s Modulus, Poisson’s Ratio, Shear Modulus, Bulk Modulus, and Minimum Horizontal Stress are determined from Conventional Logs such as Gamma Ray and Density Log utilizing ANN. Ultimately, data-driven models are developed to predict accurate geomechanical properties for future wells of the Upper and Middle Bakken Formation. Finally, the efficacy of the data-driven models achieved is tested on randomly selected new wells that were not used in the training of the model. The accurate prediction and analysis of these properties help in better reservoir characterization and efficient production from the future wells in the Bakken Formation.

This study created a new tectonic model for the Arctic Alaska terrane (AAT) by connecting attributes interpreted from surface and subsurface maps. Lineaments that cross the Brooks Range and North Slope proclaim the presence of basement fault blocks trending to the northeast that locally are aligned with streams, coast and lake shorelines, submarine canyons, and periglacial features. These landforms and anomalies reflect upward propagation of long-lived transcurrent and rift fault fabrics. Facies mapping and analysis of heat-flow effects on permafrost, and data from aeromagnetic, gravity and reflection seismic surveys, support the correlation of basement faulting with geomorphic patterns. The conjugate pattern of fault blocks, seen across Paleozoic- and Mesozoic-age passive margin sequences, resembles a piano keyboard and was inherited from older rift margin and transcurrent-transfer faults. Seismic data and North Slope oil-reservoir characteristics reveal complex fault-block boundaries, and common fault reactivation and structural inversion. The rigid North American craton in the Yukon Territory directs deformation westward leading to continued crustal indention, migration of basement blocks, and thrusting of cover rocks north of the Arctic oroclinal bend. Differential south-vergent underthrusting and uplift of the basement blocks of the North Slope plate has episodically segmented and partitioned strain across the overlying weaker north-vergent cover rocks of the North Alaskan plate. These tectonic controls have influenced the structural and geomorphic evolution of the North Slope-Brooks Range foothills region, including the formation of oil and gas reservoirs and mineral deposits.

Petroleum is generated from finely grained source rocks rich in organic materials and accumulated and trapped in reservoir rocks with relatively higher permeability and porosity. Expulsion of petroleum through and out of source rocks is called primary migration. Primary migration, as a link between source rocks and carrier rocks, presents a vital challenge to the society of petroleum geosciences and exploration and attracts the research interests of many geologists and geochemists. Despite extensive research the effective mechanisms responsible for primary migration of hydrocarbons are still in intensive debate.

Conversion of kerogen to oil and/or gas results in appreciable volume increase due to the density difference between the precursor and the products. Overpressure is developed as a natural consequence in well-sealed dense source rocks at great depths. When the overpressure reaches some critical value, bedding-parallel microcracks are initiated owing to laminated structure and strength anisotropy of source rocks. As transformation proceeds, microcracks are driven to grow subcritically by the overpressure. Such microcracks serve as migration conduits for hydrocarbon flow and may connect to other preexisting conductive fractures to form fracture networks or systems, which may facilitate further migration of hydrocarbons. Convincing evidence from observations in nature and laboratory experiments is found to support the idea that microcracks caused mainly by overpressure buildup from hydrocarbon generation functions as effective primary migration pathways. Based on those published findings, the present dissertation adopted an integrated approach consisting of petroleum geochemistry, petrophysics and fracture mechanics to assess the role of self-propagating microfractures as an effective mechanism for primary migration of hydrocarbons. Four models were developed: migration though subcritical propagation and coalescence of collinear oil-filled cracks, migration through subcritical propagation of an oil-filled penny-shaped crack in isotropic source rocks, subcritical growth of a penny-shaped crack filled by hydrocarbon mix in anisotropic source rocks, and a penny-shaped crack driven by overpressure during conversion of oil to gas. To predict the migration time and quantities of oil and natural gas, we use the reaction kinetics taking into account of pressure and temperature histories during continuous burial of sediments. To account for the compressibility of gas at high temperatures and pressures, we adopt an equation of state for methane, the predominant component of natural gas. To address the excess pressure buildup through volume expansion associated with kerogen degradation and initiation of microfractures, we employ linear fracture mechanics. To simulate the propagation of microcracks, hence the migration of hydrocarbons, we use a finite difference approach. The time period for pressure build-up, the overpressure evolution over time, and crack propagation distance and duration are determined using the coupled model where the interaction of hydrocarbon generation and expulsion is included. A detailed systematic parametric study is carried out to investigate the sensitivity of hydrocarbon migration behavior to variations in the input parameters including elastic and fracture properties of source rocks, richness and type of organic matter and burial history.

Oil retained in the microfractures may be subjected to thermal cracking to form gas when the gas window is reached as the temperature and pressure continue to increase with the progressive burial. Numerical results are presented for the two cases: kerogen conversion to hydrocarbon mix and subsequently oil conversion to gas. The modeling results agree well with published geological observations which suggest that microfractures caused by overpressures mainly due to hydrocarbon generation serve as effective migration pathways for hydrocarbons within well-sealed source rocks under favorable burial conditions. The fully coupled multiphysics modeling allows us to gain some insight on the primary migration of hydrocarbons, which is essential for the exploration of source rocks.

Due to a constantly increasing global energy demand on one side, and depletion of available hydrocarbon resources on another, a continuous search for new reserves of hydrocarbons is required (BP Energy Outlook 2035 [1]). Having in mind that estimated 22% of the world’s undiscovered petroleum is located in the Arctic, 84% of which is projected to be offshore (US Geology Survey [2]), the Arctic becomes a logical region of activities expansion for the oil and gas industry. Opposing large expected quantities of hydrocarbons that are to be found in the Arctic, there are also numerous challenges that need to be overcome in order to make production economically feasible. One of the segments of offshore production process that is expected to be influenced by Arctic conditions is upstream supply chain, or chain of delivery of products and services that are necessary for unhindered operation of an offshore field. Within upstream supply chain, it is expected that the configuration of Offshore Supply Vessel (OSV) fleet will be significantly affected by specific Arctic conditions, mainly by large distances to supply base as well as by environmental conditions. Therefore, this paper seeks to identify an optimal composition of OSV fleet taking into consideration specific Arctic conditions. A simulation model describes an upstream supply chain taking into consideration stochastic nature of environmental conditions in the Arctic. An optimization model is built on top of the simulation model in order to assess optimal configuration of the fleet with respect to operational costs. Simulation and optimization are run for a case of an offshore oil and gas field development in the Russian Arctic.

Abstract Objectives/Scope The amount of time and effort required to access and integrate Subsurface data from multiple sources is significant. Using Advanced Data Analytics, mainly python, an integrated subsurface dashboard titled Hybrid Integrated Visualization Environment (HIVE) was created using Spotfire to empower the integrated Exploration, Development and Well Reservoir and Facilities Management (WRFM) subsurface teams in: Professionalizing data and knowledge management to have "one" version of the truth. Data consolidation and preparation to avoid repetitive manual work & Enhancing opportunity identification to optimize production and value Methods, procedure, process The approach of subsurface data integration can be broken down into 4 major steps, namely: Step 1: Python programming was used to pre-process, restructure and create unified data frames. Use of python significantly reduces the time required to pre-process a diverse number of subsurface data sources consisting of static, dynamic reservoir models, log data, historical production & pressure data and wells & completion data to name a few. Step 2: - Standard diagnostic industry recognized diagnostic plots were automated using advanced analytic techniques in HIVE with the help of unified data frames. Step 3: HIVE was created to link various internal corporate data stores like pressure, temperature, rate data from PI System (stores real time measured data), Energy Components (EC) and Oil Field Manager (OFM) in real time. This was done to ensure that data from various petroleum engineering disciplines could now be visualized and analyzed in a structured manner to make integrated business decisions. Step 4: One of the key objectives of pursuing this initiative was to ensure that subsurface professionals in Shell Trinidad and Tobago were trained and upskilled in the use of python as well visualization tools like Spotfire and Power BI to ensure the maintenance and improvement of HIVE going forward. Results, Observations, Conclusions The development of HIVE has made it easier and more efficient to access and visualize subsurface data, which was extremely time consuming earlier while using older conventional techniques. Standard diagnostic plots and visuals were developed and are now used to drive integrated decision making, with key focus being water and sand production management from a production management perspective. Consequently, HIVE also drives enhanced integration between disciplines (Petrophysics, Petroleum Geology, Production Technology, Reservoir Engineering and Production operations) and departments (Developments, Upstream and Exploration). Novel/Additive Information The petroleum industry has started to embrace the application of advanced data analytics in our day-to-day work. A successful application of these techniques results in transforming the ways of working by increasing efficiency, transparency and integration among teams.

The oil and gas industry has, over the recent years, invested heavily in multi-billion dollar projects aimed at developing an exploration and production infrastructure in the deepwater Gulf of Mexico. The integrity management of such facilities will be critical for the industry in the coming years. Competency of Personnel stands out as the most important of these areas. Although office-based personnel plays an important part, the personnel working offshore such as OIMs, supervisors, ballast operators and topsides operators will make critical decisions that may affect the safety of an entire production unit. Alliances between offshore industries, contractors and community colleges generate curricula exclusively tailored to provide specific training and retraining to new hires on the duties and tasks performed by the oil and gas production technician and encumbered workers of the offshore industry. Offshore oil and gas extraction organizations are faced with unique challenges, when needing competent, skillful, safe, and well trained workers. Liabilities from non-trained personnel, and the understanding that safety is priority #1 on the platform, are paramount in concepts of the offshore workforce. Unlike other areas of the world, production in the Gulf of Mexico has been predominantly on the shallow water continental shelf and many organizations are faced with the challenges of developing new sets of skills for different types of production facilities used in deep water. Training of technicians, who will be operating an offshore deepwater platform, should cover topics that include ballast control and stability management, vessel station-keeping, riser management, response to hurricanes and loop currents, hydrocarbon and operations safety, process equipment and systems, troubleshooting, sub-surface geology, petroleum engineering and drilling technology. This paper discusses collaborative initiatives and discusses specific solutions. Based on a multi-year experience generating of such curricula, recommendations are provided to industries that want to establish such training programs for their technical personnel.