Gas Cap Research Articles

Specification of main technical parameters of reserves accumulated in the underground gas storages develo- ped in the oil fields with gas caps

The optimum variant is selected from two reviewed options for the development of gas storage of peak type, which is differed with storing capacity and daily tools of gas intake. Based on the data, the average values of coefficients of filtration resistance for a gas well were calculated. The parameters of the gas storages were revealed by means of the calculations, due to which the rules of control and field regulation specified as well. In accordance with the results provided and further increase of gas saturated volume, the capacity of produced oil in the presence of gas repression in the gas zone by the change of dynamics of the volume of gas saturated pores and formation pressure is specified

Neutron Response Modeling to Track Lean Gas Plume in Recycled Gas Cap Reservoir in Concurrent Gas Cap-Oil Rim Development: A Step Forward

Summary Gas cap pressure maintenance while developing the associated oil rim is a critical aspect for optimum recovery. Preventing gas cap pressure dropping below dewpoint by injecting lean gas is essential for concurrent gas cap-oil rim development. Reservoir heterogeneity aggravates lean gas override causing preferential movement of lean gas plume. Thus, it is important to track lean gas plume while recycling and understanding the breakthrough potential of lean gas. This paper demonstrates a new workflow to track lean gas plume by estimating phase saturations with a case study from one of the giant oil and gas fields, Onshore, Abu Dhabi. Pulsed neutron capture (PNC) tools are used for reservoir monitoring and surveillance. However, sigma log evaluation is insufficient to derive individual hydrocarbon phase saturations to monitor lean gas plume. Neutron response modeling (NRM) is devised to differentiate between lean and rich gas. NRM is a probabilistic solver with input of mineral and fluid phase parameters into tool response functions in petrophysical evaluation. To distinguish with discrete neutron fluid response between lean and rich gas, pressure/volume/temperature (PVT) data are utilized to derive hydrogen index, capture cross section, thermal decay length, and neutron macro parameters, such as neutron slowing down length and migration length. Neutron response is investigated for lean and rich gas with sensitivity of invasion effects on neutron log by calibrating to core porosity. The response for each phase under thermal neutron and capture modes with corresponding raw neutron log statistics is reviewed in both openhole and casedhole environments in known lean/rich gas intervals. Thirty-five wells spread across gas cap and oil leg with quality neutron log data are modeled and individual phase saturations are estimated. The target reservoir is under development with over three decades of lean gas injection to support oil production. NRM results and phase saturations are validated with recent formation sampling, which enhanced the confidence in the overall workflow. Later, the results are verified to be in excellent agreement with lean gas injection and production history of the target reservoir. The identified movement of lean gas highlights nonuniform geology and gravity segregation of injected lean gas into upper members of the target reservoir. The results also emphasized the need for better injection support to lower members of the target reservoir where gas cap development is ongoing. The solution presented is unique, particularly for lean gas injection projects by utilizing PVT for NRM based on neutron transport mechanism in pore fluids. Existing workflows require a special nuclear modeling platform with computationally expensive processing on data sets acquired using advanced logging technology. In spite of these prerequisites, existing workflows are not able to distinguish lean gas over rich gas. This paper effectively demonstrates NRM workflow distinguishing lean gas plume from rich gas using neutron logs and reveals compelling reservoir management insights. The sensitivity studies and practicality of this workflow highlight the fundamental importance of neutron logs in mature fields.

Geoscience Poster G9: Optimising value in the mature Turrum Field: integrating modern seismic, high-resolution sequence stratigraphy and production data in a 3D geological model

Poster G9 The Turrum Field in the offshore Gippsland Basin has been a significant producing field since first development in 2004 and remains a keystone gas resource for the future as many of the Gippsland assets continue to deplete. The Turrum Field is a faulted anticlinal structure with multiple, stacked, Paleocene-aged fluvial to lagoonal reservoirs that stratigraphically sit below the overlying Marlin Field gas cap. This field was developed in two phases with drilling campaigns in 2004 and 2015 and includes a dedicated platform (Marlin B) for the higher pressure, higher CO2 gas. Leveraging the 2018 reprocessed Northern Margins 3D seismic survey with a modern broadband processing workflow and wider bandwidth and higher signal-to-noise ratio has led to a seismic image with greater resolution and allowed improved reservoir characterisation. The uplift in seismic data together with the colour blending capabilities in GeoTeric®, has led to the seismic identification of large-scale fluvial reservoir systems. These products have been integrated with a revised field-wide sequence stratigraphic framework, petrophysical analysis and incorporated into a full-field 3D geological model of the Turrum Field. The resultant geological model has improved our understanding of reservoir connectivity and will enable rapid integration of production and surveillance data to optimise gas deliverability. This will also provide increased confidence for future field depletion planning including the identification of potential bypassed gas opportunities prior to end of field life. To access the poster click the link on the right. To read the full paper click here

LINEAR STABILITY OF A FILTRATION FLOW WITH GAS–OIL INTERFACE WITHIN THE BRINKMAN APPROACH

Abstract—The problem of vertical flow stability in an oil reservoir with a gas cap is considered, when the oil flow obeys the Brinkman equation. Boundary conditions at the moving boundary of the gas-oil interface are derived and a basic solution is obtained. The normal mode method is used to study the stability of the gas–oil interface. The obtained dispersion equation is investigated. Conditions for flow stability are found for all values of the parameters, and it is shown that, in the linear approximation, the growth rate of short-wave perturbations tends to zero with increasing wave number.

Experimental study of the development mode of gas-cap edge-water reservoir: A case study of Khasib reservoir of Halfaya oilfield in Iraq

Based on the oil, gas and water distribution characteristics of Khasib reservoir in Halfaya oilfield, Iraq, a core displacement experiment is designed to evaluate the influence of different displacement methods and displacement parameters on oil displacement efficiency. The research shows that, in the displacement method with water injected from the edge of the reservoir, early depletion production is conducive to the elastic expansion of the gas cap, forming the three-dimensional displacement of “upper pressure and lower pushing”, and the oil displacement effect is good. When gas injection at the top and water injection at the edge are used for synergistic displacement, the injection timing has different influences on the oil displacement effects of high and low parts. Considering the overall oil displacement efficiency, the injection pressure should be greater than the bubble point pressure of crude oil. Two displacement methods are recommended with the reasonable injection time at 20–25 MPa. The injection speed has the same influence on different injection media. Appropriately reducing the injection speed is conducive to the stability of the displacement front, delaying the breakthrough of injection media and improving the oil displacement effect. The reasonable injection rate of water flooding is 0.075 mL/min, the reasonable injection rates of water and gas are 0.15 mL/min and 0.10 mL/min, respectively in gas-water synergistic displacement. Gas-water synergistic displacement is conducive to the production of crude oil at high position, and has crude oil recovery 5.0%–14.8% higher than water flooding from the edge, so it is recommended as the development mode of Khasib reservoir at the middle and late stages.

A comprehensive performance evaluation methodology for miscible gas flooding: A case study in a giant carbonate reservoir in Middle East

This work focuses on a typical low-permeability carbonate reservoir in Middle East that has been developed by miscible hydrocarbon (HC) gas flooding for more than 10 years. The oilfield is now suffering from gas channeling, high gas/oil ratio (GOR), and invalid gas circulation. To figure out the reasons and propose an optimized development plan, it is necessary to accurately determine the characteristics and behavior of miscible gas flooding. To achieve this, a comprehensive performance evaluation method for miscible gas flooding is established in this work by integrating production data, inter-well gas tracer test, saturation surveillance, pressure surveillance, minimum miscibility pressure (MMP) variation, and streamline simulation. The following miscible HC gas flooding characteristics are interpreted, including typical gas flow path, miscibility behavior, major controlling factors impacting performance, and the main challenges of the current development scheme, which provides a fundament for proposing mitigation plan. By using this evaluation method, the behavior of gas flow in the ongoing miscible flooding process is precisely characterized, which is a “gravity override-gas coning” mode in which gas override is formed by an upward injected gas flow and then gas flows through gas cap to producers that leads to gas coning, resulting in high GOR and invalid gas circulation. This flow mode mainly resulted from the unsatisfied miscibility that led to gas escaping from miscible phase and gas channeling. Furthermore, it was found out that pressure difference is the dominating factor for gas channeling. In addition, we also found that MMP varies during HC gas injection process due to the change in the oil composition, which emphasizes the importance of recovering and maintaining pressure. Based on these findings obtained from extensive dynamic performance analysis and numerical simulations, an optimization strategy is finally proposed for improving the performance of miscible HC gas flooding.

Optimising value in the mature Turrum Field: integrating modern seismic, high-resolution sequence stratigraphy and production data in a 3D geological model

The Turrum Field in the offshore Gippsland Basin has been a significant producing field since first development in 2004 and remains a keystone gas resource for the future as many of the Gippsland assets continue to deplete. The Turrum Field is a faulted anticlinal structure with multiple, stacked, Paleocene-aged fluvial to lagoonal reservoirs that stratigraphically sit below the overlying Marlin Field gas cap. This field was developed in two phases with drilling campaigns in 2004 and 2015 and includes a dedicated platform (Marlin B) for the higher pressure, higher CO2 gas. Leveraging the 2018 reprocessed Northern Margins 3D seismic survey with a modern broadband processing workflow and wider bandwidth and higher signal-to-noise ratio has led to a seismic image with greater resolution and allowed improved reservoir characterisation. The uplift in seismic data together with the colour blending capabilities in GeoTeric®, has led to the seismic identification of large-scale fluvial reservoir systems. These products have been integrated with a revised field-wide sequence stratigraphic framework, petrophysical analysis and incorporated into a full-field 3D geological model of the Turrum Field. The resultant geological model has improved our understanding of reservoir connectivity and will enable rapid integration of production and surveillance data to optimise gas deliverability. This will also provide increased confidence for future field depletion planning including the identification of potential bypassed gas opportunities prior to end of field life.

Approximation of the compression process to isothermal in a reciprocating compressor with a liquid piston

• Theoretical and experimental study of bringing the compression process to isothermal. • Designed two-stage piston hybrid power machine with liquid piston. • The kinematics of liquid piston motion has three zones: two isothermal (hyperisothermic) and one non-isothermal compression. • With a decrease in the temperature of the surface of the working chamber and its diameter, the average velocities of the liquid piston of the real and isothermal compression process converge. • According to the obtained results, new highly efficient designs of hybrid power machines are proposed. The implementation of the isothermal process of gas compression in the compressor increases the indicator efficiency up to 20%, which is a determining increase in their operation and saves a significant amount of energy and financial resources, as compressor units consume up to 10% of the energy consumed by production sector. Its implementation is possible in many ways: by changing the heat exchange surface (injection of coolant during compression), changing the heat transfer coefficient, changing the speed of gas compression, etc. The article considers a scheme for gas compression in a cylinder with a liquid piston having a variable speed to ensure an isothermal compression process, and a design of piston hybrid power machine, which brings the gas compression process closer to isothermal. According to theoretical studies, we determine the speed of the liquid piston for the implementation of the isothermal compression process, the amount of liquid required to supplied to the cylinder and the amount of liquid to be be drained from the pump into the gas cap. Using the method of mathematical modeling, according to the fundamental laws of conservation of energy, mass and motion, a mathematical model of a two-stage piston hybrid power machine with a liquid piston and a gas cap has been developed. The performance of the machine is verified by the created prototype, a test stand for its research and a series of experimental studies. As a result of the numerical experiment, we determined the physical picture of the processes in the machine, the absolute and relative flow rates of liquid into the gas cap and into the working cavity for isothermal compression process. The comparative analysis of the relative and absolute flow rates of the liquid and the instantaneous velocities of the piston identified areas by the angle of rotation where the isothermal compression process or close to it is carried out and where it is difficult. The performed parametric analysis verified that reducing the temperature of the walls and the diameter of the cylinder improves the implementing of the isothermal compression process. Using the findings, the results of the conducted patent analysis on the design features of the PHPM, we offered ways to implement the isothermal compression process, new two-stage PHPM designs with a liquid piston having high weight, size and energy indicators.

Heat-Resistant CO2 Foam for Promoting Carbon Capture and Enhanced Oil Recovery

Investigation of methods to effectively block the high-permeability channel and displace the residual oil in the small pores in the old oilfields is an urgent research hotspot. The heat-resistant carbon dioxide (CO2) foam with high viscoelasticity and low interfacial tension, which is suitable for improving the oil recovery of old oilfields, and at the same time aids in carbon sequestration. In this study, a suitable heat-resistant foaming agent was selected by considering the temperature resistance, plugging, and profile control as the evaluation indicators, and the heat-resistant CO2 foam was prepared. Then, the two-dimensional (2D) plate model experiment was designed to verify the feasibility of the heat-resistant CO2 foam profile control process in order to solve the problems of small sweep range and uneven sweep degree in the reservoir. The results show that the selected foaming agent (RSB-IV) still maintained a foaming volume of 375 ml at 300°C, and the interfacial tension was only 0.008 mNm−1. The prepared heat-resistant CO2 foam exhibited the best profile control effect when the gas and liquid mixed injection, the gas-liquid ratio was 1:1, and the injection volume was 4.5–5.5 PV. In the 2D plate experiment, heat-resistant CO2 foam flooding promoted the recovery of the remaining oil in the matrix, and the oil recovery was increased to 61.01%. Furthermore, by designing the CO2 gas cap, it was verified that when the volume of the gas cap was large (above 1.5 PV), the injection of the CO2 gas cap could not only effectively improve the recovery rate, but also achieve effective CO2 capture.

Importance of reservoir simulation and early reservoir management for successful field development — Case study

The current RF (recovery factor) of the subject reservoir is <10%, considered uncharacteristically low for a high porosity and permeability reservoir. Detailed studies were conducted to find out the reasons behind the reservoir’s very low RF. Applying analytical tools, we learned that; (1) a bottom aquifer supported more than 70% of the reservoir energy, (2) excessive free gas production occurred, and (3) productivity of almost all the wells was deteriorated by water/gas coning. Multiple simulation runs were conducted to achieve a reasonable history matching of 47-year long field production and pressure profiles. Results show that initial oil–water and gas–oil contacts moved up considerably in the reservoir. Consequently, a significant gas cap re-saturation happened. This resulted in a very low RF and failure of several wells. These findings are in close agreement with the material balance results and log analysis. Nearly 40% of original oil-in-place moved into the initial gas cap which could have been prevented by controlling producing GOR (gas–oil ratio) and reservoir pressure, and close monitoring of fluid contacts.Alternative RM methodologies of reservoir were investigated showing that the RF could have been as high as 35%, utilizing four horizontal wells with an average horizontal section of about 800 m located in the middle of oil column, and controlling producing GOR. That proves that high oil recovery with significant economic benefits can be achieved by utilizing horizontal wells in development of the oil reservoirs with a large gas cap and strong aquifer. Finally, this study highlights the need of performing analytical analysis for a reservoir experiencing complex behavior prior to reservoir simulation study to get more reliable understanding of the reservoir behavior, establish consistency across the various datasets, and also provide initial field development planning insights.

Technology Focus: Completions (April 2022)

Data science continues to provide solutions for unconventional-well challenges. But innovative combinations of proven technologies also are delivering improved success in artificial lift wells. The articles I have selected for this feature provide details on these achievements. But can the learnings from one type of completion improve success in other types of completions? The shale gas revolution is over 20 years old. The pace of innovation has been rapid, and many technologies and methods have been developed that reduce completion time and maximize access to the reservoir with one well. Unconventional-well innovation, therefore, has led to constant improvements in efficiency and reliability. There is no doubt this will continue, but can unconventional learnings be applied in conventional completions? Electrical submersible pumps (ESPs) and intelligent-completion technologies are complementary, but each have very different service lives. For example, intelligent-completion hardware may have a 20-year service life, while ESPs may have a 2-year service life. So how can they be integrated in a way that ensures long-term reliability in the intelligent completion while accommodating periodic ESP workovers? Reimagining completion architecture is one way that a Middle East operator has achieved this goal. Can large logging-while-drilling and measuring-while-drilling data sets be used to optimize completion of the well? One paper explains how perforation cluster design in Marcellus wells can be optimized by analyzing these data sets using a convolutional neural network model. The key to optimization involves mechanical specific energy. Is the lesson here to drill with the completion in mind or to complete with drilling in mind? Will drilling engineers and completion engineers answer the last question differently, or will they agree on a different paradigm for the next well or project? It has been said that you will get the same result by repeating what you have done. But if you want to have a better result, you must change what you are doing. Is it time for a paradigm shift? Recommended additional reading at OnePetro: www.onepetro.org. SPE 199712 - Evaluating Limited-Entry Perforating and Diverter-Completion Techniques With Ultrasonic Perforation Imaging and Fiber Optic DTS Warmbacks by Chase Murphree, SM Energy, et al. SPE 207862 - Modeling a Novel Approach To Delay the Water Breakthrough in Gas Cap Wells Using Smart Completions: Case Study Onshore Abu Dhabi Field by Aditya Ojha, ADNOC, et al. SPE 201268 - DTS Flow Profiling for a Horizontal Multistage Fractured Well in Tight Gas Reservoirs by Improved Model Considering an Openhole Packer Completion Scenario by Weibo Sui, China University of Petroleum, et al.

Experimental Study on Gas–Liquid Interface Evolution during Liquid Displaced by Gas of Mobile Pipeline

The mobile pipeline is the most effective and reliable means for the emergency oil transfer task, which is temporarily laid on the field. After completing the task, the oil in the pipeline should be emptied before the mobile pipeline is removed. The oil in pipeline gradually displaced by the air is a main method of pipeline evacuation, which is the only choice of jet fuel pipeline. Due to the convection between gas and oil phases, the length of the oil–gas mixing section and the evolution of the oil–gas interface change with time. The evolution of the gas–liquid interface directly determines the different flow patterns of oil–gas two phases, which are very important for the mobile pipeline evacuation. In this paper, the characteristics of the gas–liquid interface evolution during the water displaced by air are studied, using the multi-phase pipeline experiment. Through the change of the gas–liquid interface in the initial stage of gas cap evacuation, it is found that the gas–liquid interface can be divided into smooth, wavy, and dispersed forms under different initial gas flow rates and different inclination angles. Slug phenomenon may occur in the process of gas-carrying liquid flow in the pipeline. The emergence of slug is mainly affected by hydraulic conditions and pipeline operating conditions. The liquid plug body is complex and unstable, and there will be a mutual transition between different liquid slug shapes. The increase of the inclination angle and gas phase velocity will accelerate the occurrence of liquid slug frequency.

Laboratory Studies for Design of a Foam Pilot for Reducing Gas Channeling from Gas Cap in Production Well in Messoyakhskoye Field

Summary This paper highlights the difference between foam injection for gas blocking in production well and injection well and emphasizes the use of polymer enhanced foam. Moreover, this paper shows systematic experimental methods for choosing suitable foam systems for gas blocking in production well considering different factors, which provides a guide regarding what kinds of foaming agents and polymer stabilizers should be used and how to evaluate them for designing a pilot application. The target in this work is the Vostochno-Messoyakhskoye field, operated by Gazpromneft, which is currently experiencing gas channeling from the gas cap in production wells because of strong heterogeneity. Foam has long been considered as a good candidate for gas blocking. However, foam injection for gas blocking in production wells is different from that in injection wells, which requires a long-term impact on gas-saturated highly permeable areas without significantly affecting the phase permeability of oil in the reservoir. Therefore, for gas blocking in production well, a long half-life time of foam is required to sustain stable foam because a continuous shear of surfactant solution/gas cannot be achieved as in injection wells. Thus, reinforced foam by polymer (polymer-foam) is chosen. Four polyacrylamide polymer stabilizers and five anionic surfactants were evaluated using bulk test to determine foaming ability, foam stability, and effect of oil by comparing foam rate and half-life time to determine the suitable foam system with optimal concentrations of reagents. Furthermore, filtration experiments were conducted at reservoir conditions to determine the optimal injection mode by evaluating apparent viscosity, breakthrough pressure gradient, resistance factor, and residual resistance factor. Polymer can significantly improve half-life time (increase foam stability), and the higher the polymer concentration, the longer the half-life time. But simultaneously, a high polymer concentration will increase the initial viscosity of the solution, which not only decreases the foam rate but also increases difficulties in injection. Therefore, an optimal polymer concentration of about 0.15–0.2 wt% is determined considering all these influences. Filtration experiments showed that the apparent viscosity in the core first increased and then decreased with foam quality (the volumetric ratio of gas to total liquid/gas flow). The optimal injection mode is coinjection of surfactant/polymer solution and gas to in-situ generate foam at the optimal foam quality of about 0.65. Filtration experiments on the different permeability cores showed that the gas-blocking ability of polymer-foam is better in high-permeability cores, which is beneficial for blocking high-permeability zone. It should also be noted that under a certain ratio of oil-to-foam solution (about lower than 1 to 1), the presence of high-viscosity crude oil slowly decreased the foam rate with increasing oil volume, but significantly increased the half-life time (i.e., foam stability which is favorable for foam treatment in production well).

Inflow Control Devices Placement: A Computational Fluid Dynamics Approach

Summary Nowadays, it is common to use horizontal wells to improve the oil production rate. The production rate varies along the horizontal well because of either frictional pressure losses (the heel-toe effect) or reservoir heterogeneity. Such a flux variability in zones close to the bottomwater and gas cap leads to water and gas breakthroughs. To mitigate water (or gas) coning, inflow control devices (ICDs) have become a standard practice to control instability and improve uniformity in the inflow profile. These devices help delay the water (or gas) breakthroughs by exerting a greater restriction on high water/oil ratio (or gas/oil ratio) zones. In the design and analysis of ICDs, the only sensible method is to model these tools using the numerical simulation that couples the well and the reservoir. Reservoir and production engineers formulate the ICD characteristics using expensive and time-consuming flow loop testing. In some scenarios, fluid flow simulations using computational fluid dynamics (CFD) are used to compare the results with the flow loop. However, owing to convergency issues in CFD and the unavailability of an established framework, the CFD results are not used to formulate the ICDs in the reservoir models. Instead, different types of empirical correlations are used to describe the ICDs, which require many empirical factors, causing inconsistencies in calculations. In this study, we first use CFD to characterize an orifice-based ICD in terms of the Reynolds number. Then, the results are formulated in a correlation that provides a consistent approach from CFD to well/reservoir modeling. Using such a framework, operators can ensure their prototypes are suitable for any specific problem by altering the geometry and simulating several scenarios from CFD to well/reservoir model.

Prediction of gas coning in hydrocarbon reservoir using tNavigator

Several approaches for avoiding gas breakthrough due to coning phenomena have been proposed. These methods include maintaining oil production rates below critical rates, inserting crosslinking gels near the well to create a gas-blocking area, and making perforation as far away from the initial gas-oil contact (GOC) as possible, often considered uneconomically solutions and not sufficient way to deal with the problem. Furthermore, this is a major source of concern in terms of the additional costs of separation procedures and equipment availability. Coning couldn’t possibly be totally eliminated, but it can be minimized by defining the breakthrough time and understanding the characteristics that have a significant impact on breakthrough time and how effectively may be manipulated to delay it. A mathematical and numerical approach was used in this research for the purpose of gas breakthrough time investigation and monitoring the gas-oil ratio (GOR). tNavigator embedded flow equation was used as a novel 3D compositional simulation principle in the software to predict the time of gas flow from grid cell to another reaching the perforation interval, for the purpose of utilizing the sensitivity analysis of certain parameters which had sufficient impact on GOR value and breakthrough time (tBt). Results show that the Oil column is the most effective parameter in the sensitivity analysis and the one factor to focus on while producing from gas cap reservoirs.

Lessons learned from the integrated multifarious study of a poorly performing yet great quality oil reservoir: an example from Assam Basin, India

A bafflingly low recovery factor (<10%) of a sandstone reservoir (average porosity 20%, permeability 500 md) was investigated. This situation was attributed to complex fluid movements in response to aggressive gas production, a strong bottom-water aquifer, and reservoir heterogeneity. Some higher productivity wells are situated in high seismic amplitude regions. Material balance studies indicated the presence of an initial gas cap, strong bottom-water drive, and major upward fluid movement due to excessive early gas production. Detailed analyses of well logs and pressure-production-PVT data confirmed temporal movement of contacts. Oil segregation inferred from geochemical analysis indicated reservoir heterogeneity, also supported by seismic amplitude variations. This situation, combined with differential drawdowns, resulted in substantial non-uniform distribution of moved oil into the initial gas cap, causing unpredictable reservoir behavior, well failures, and early water breakthroughs. Remedies include shutting down wells with high gas-oil ratios and water cut, and modeling studies to locate moved oil. This study reinforces: (1) criticality of periodic integration of multifarious dataset, (2) reservoir monitoring, especially ones with large gas caps, and that (3) for maximum recovery from similar reservoirs, oil should be produced first, carefully managing initial gas cap- and water-drive energies, followed by remaining gas production.

Diamondoid fractionation and implications for the Kekeya condensate field in the Southwestern Depression of the Tarim Basin, NW China

Oil and condensate reservoirs frequently experienced later gas charging and cap gas leakage. The influences of these two processes on diamondoid concentrations and compositions are not well documented. To investigate these issues, quantitative GC, GC-MS and GC-IRMS analyses were performed on 24 condensates from the Kekeya Field of gas condensate in the Southwestern Depression of the Tarim Basin, northwestern China. Only normal oils filled the reservoirs of this field prior to gas charging. Based on biomarker concentrations and carbon isotopic composition of individual n-alkanes, these oils were derived from multiple source rocks within the Permian and Middle–Lower Jurassic strata within the early to late window of oil generation. Diamondoid concentrations and compositions of condensates were mainly controlled by the gas that subsequently charged the reservoirs and the extents of cap gas leakage. Two deeper condensates KS101C2 and KS101C3 at 6651–6835 m have extremely high concentrations of 4- + 3-methyldiamantanes (4 + 3MD) in the range of 2523–4296 ppm and very low ratios of adamantane/diamantane (A/D) and methyladamantanes/methyldiamantanes (MAs/MDs) in the ranges of 0.10–0.11 and 0.28–0.33, respectively, demonstrating that these reservoirs were charged by the primary gas with high diamondoid concentration that was generated from very deeply buried source rocks at post mature stage in combination with extensive leakage of the cap gas (the secondary gas). The shallower condensate K2C2 at 3319–3326 m has a moderate 4 + 3MD concentration of 18 ppm and very low ratios of A/D and MAs/MDs of 0.00 and 0.19, respectively, demonstrating that this reservoir was charged by the secondary gas in combination with extensive leakage of the cap gas (the third-generation gas). The shallower condensate KX3C at 3765–3820 m has a lower 4 + 3MD concentration of 9 ppm but very high ratios of A/D and MAs/MDs of 8.60 and 16.73, respectively, demonstrating that this reservoir was charged by the third-generation gas with or without minor cap gas leakage. The other twenty condensates have 4 + 3MD concentrations in the range of 7–23 ppm and ratios of A/D and MAs/MDs in the ranges of 0.60–5.29 and 2.18–12.18, respectively, demonstrating that these reservoirs were charged by the secondary or/and third-generation gases with different extents of cap gas leakage. Furthermore, cap gas leakage influenced alkyladamantane ratios of MAI, DMAI-1, TMAI-1, TMAI-2 and EAI but not the alkyldiamantane ratios of MDI, DMDI-1 and DMDI-2 for maturity and source.

Underground Gas Storage Construction in Gas Fields with Oil Ring and Edge and Bottom Water: A Case Study

ABSTRACT Most underground gas storages (UGSs) are constructed in gas fields, but there are few UGS examples constructed in a gas field with an oil ring and edge/bottom water (OR-EBW-gas field). In areas where suitable gas fields are not available for USG development, existing gas fields with oil ring and edge and bottom water have to be used to construct UGS to balance the seasonal natural gas consumption and supply. Compared with conventional gas reservoirs, fluid distribution is much more complicated in OR-EBW-gas fields and there exist different modes for storage space plan, which brings up more uncertainty for the UGS construction. In this work, an active UGS construction in an OR-EBW-gas field is studied using a comprehensive compositional numerical model. The operation parameters are firstly determined through detailed sensitivity studies. UGS construction schemes employing different porous medium spaces are then investigated to determine the optimal one. The results indicate that UGS constructed using gas cap area is the optimal scheme. After 20 I/W cycles, the predicted working load of the UGS is 1.726 × 108 m3, which reaches the designed value of 1.7 × 108 m3. The incremental cumulative water production and oil production are 0.21 × 104m3 and 0.42 × 104m3 respectively. The study shows that it is crucial to prevent the intrusion of edge water for UGS construction in an OR-EBW-gas field. The oil ring is not suitable for UGS construction due to its poor petrophysical property, but can be used as a natural barrier to separate gas cap and edge water. The formation pressure needs to be improved when the gas cap, oil ring and edge water are selected as USG construction zones. However, it will also lead to a significant increase in the formation pressure near the main control fault, which leads to a high risk of fault failure.

Integrated fracture characterization of Asmari reservoir in Haftkel field

The Asmari reservoir in Haftkel field is one of the most prolific naturally fractured reservoirs in the Zagros folded zone in the southwest of Iran. The primary production was commenced in 1928 and continued until 1976 with a plateau rate of 200,000 bbl/day for several years. There was an initial gas cap on the oil column. Gas injection was commenced in June 1976 and so far, 28% of the initial oil in place have been recovered. As far as we concerned, fracture network is a key factor in sustaining oil production; therefore, it needs to be characterized and results be deployed in designing new wells to sustain future production. Multidisciplinary fracture evaluation from well to reservoir scale is a great privilege to improve model’s accuracy as well as enhancing reliability of future development plan in an efficient manner. Fracture identification and modeling usually establish at well scale and translate to reservoir using analytical or numerical algorithms with the limited tie-points between wells. Evaluating fracture network from production data can significantly improve conventional workflow where limited inter-well information is available. By incorporating those evidences, the fracture modeling workflow can be optimized further where lateral and vertical connectivity is a concern. This paper begins with the fracture characterization whereby all available data are evaluated to determine fracture patterns and extension of fracture network across the field. As results, a consistent correlation is obtained between the temperature gradient and productivity of wells, also convection phenomenon is confirmed. The findings of this section help us in better understanding fracture network, hydrodynamic communication and variation of temperature. Fracture modeling is the next step where characteristics of fractures are determined according to the structural geology and stress directions. Also, the fault’s related fractures and density of fractures are determined. Meanwhile, the results of data evaluation are deployed into the fracture model to control distribution and characteristics of fracture network, thereby a better representation is obtained that can be used for evaluating production data and optimizing development plan.

Self-Organizing-Map Approach Characterizes Naturally Fractured Reservoir in a Mature Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206027, “Naturally Fractured Basement Reservoir Characterization in a Mature Field,” by Muhammad Nur Ali Akbar, MOL Hungary. The paper has not been peer reviewed. The complete paper describes an alternative solution for identifying the presence of natural fractures, classifying them into fracture-quality-related flowability, and distributing them vertically within the well interval, and proposes a lateral distribution method for reservoir modeling. The proposed approach, using the machine-learning technique of self-organizing-map (SOM) clustering, effectively assists recognition of fracture presence and quality along the well-depth interval. Field Overview and Data Used The case study was conducted in an oil field discovered in the early 1980s in southwestern Hungary. Thirty-six wells penetrated the naturally fractured carbonate in the Triassic formation. The main lithology of this reservoir is limestone and dolomite associated with faults and exhumation breccia and marl/shale. The reservoir is saturated oil (with gas cap) with unlimited aquifer (strong water drive). The gas cap, however, is mainly composed of 85% carbon dioxide and up to 1,800 ppm of hydrogen sulfide. Generally, the oil is intermediate to heavy, with a gravity of approximately 20 °API. The reservoir rock properties of this case study are fully complex for both the pore system and its composition. In general, the matrix pore system does not significantly contribute to storativity or permeability. The effective porosity is approximately 4.2% on average. This value sometimes directs to the matrix porosity, but in this case study, high intensity of the microfracture presence behaves in a way similar to matrix porosity, a phenomenon the author terms “pseudomatrix porosity.” Moreover, the effective oil permeability value of the studied fractured reservoir is extremely high (up to 70 darcies per well-test interpretation). The permeability ranges from 1 to 2000 md in brecciated fractures or in naturally fractured rock samples. Two types of core samples were used in this study—fractured breccia and naturally fractured rock. Both types have similar behavior in terms of the porosity/permeability relationship. In this study, that relationship is not the one normally observed in clastic reservoir rock. Marl/shale content is one of the more- critical parameters, indicating low fracture quality in terms of permeability. More than 50% of the well-log data for this study were measured by Russian-type well logs, meaning that only simple electrical, gamma ray, and neutron- capture gamma logs were available. Other wells have standard triple-quad combination logs. Image logs are available only from two wells drilled in the 2000s. By considering these log-data limitations, cores, and production-test results, the study aimed to define the effective fracture locations and intervals.