Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Maximizing Recovery from a Depleted Oil Rim Carbonate Reservoir Through an Integrated FDP Approach: Case Study Onshore Field Abu Dhabi, UAE
Fathalla, Magdy Farouk (ADNOC Onshore) | Al Hosani, Mariam Ahmed (ADNOC Onshore) | Mohamed, Ihab Nabil (ADNOC Onshore) | Al Bairaq, Ahmed Mohamed (ADNOC Onshore) | Ojha, Aditya (ADNOC Onshore) | Mengal, Salman Akram (ADNOC Onshore) | Pramudyo, Yuni Budi (ADNOC Onshore) | Nachiappan, Ramanathan (ADNOC Onshore) | Bankole, Ibukun Olatunbosun (ADNOC Onshore)
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 plateau Propose 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.
- Asia > Middle East > Saudi Arabia > Thamama Group > Habshan Formation (0.99)
- Asia > Middle East > Saudi Arabia > Thamama Group > Kharaib Formation (0.94)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 6 > Lekhwair Field > Thamama Group > Thamama Group > Shuaiba Formation (0.94)
- (3 more...)
Fluid Tracking Modeling for Condensate/Oil Production and Gas Utilization Allocation โ An Abu Dhabi Onshore Example
Wang, Yun (bp) | Jerauld, Gary (bp) | Bhushan, Yatindra (Abu Dhabi National Oil Company) | Azagbaesuweli, Gregory (Abu Dhabi National Oil Company) | Bin Romeli, Mohd (Abu Dhabi National Oil Company) | Nasir, Wardah (Abu Dhabi National Oil Company) | Al Mazrooei, Suhaila (Abu Dhabi National Oil Company) | Al Ali, Mona (Abu Dhabi National Oil Company) | Singh, Manjit (Abu Dhabi National Oil Company) | Alhefeiti, Ebtisam (Abu Dhabi National Oil Company) | Al Tenaiji, Aamna (Abu Dhabi National Oil Company) | Matthews, Anna (bp)
Abstract One of the reservoirs in a giant field in onshore Abu Dhabi has been producing for six decades. The reservoir was already saturated at the time of production commencement, with a large oil rim and a gas cap. Both water injection and lean gas injection have been relied upon to sustain production, and will play an even more prominent role for the future development of oil rim and gas cap. Due to the stakeholdersโ different entitlements / equity interests in the hydrocarbons originally existed in oil rim area versus gas cap area, it is important to be able to allocate liquid hydrocarbon production and injection gas utilization among the stakeholders, based on a systematic framework. This paper presents a comprehensive comparison of two modeling-based approaches of fluid tracking for condensate allocation and gas utilization โ a tracer modeling option in a commercial reservoir simulator, and a full component fluid tracking approach implemented for this reservoir. The component tracking approach is based on the idea that if individual components represented in a fully compositional reservoir model are tracked separately starting from model initialization, one can trace back the source of hydrocarbon production from both gas cap and oil rim. This approach is implemented through the doubling of the number of components in the equation of state fluid characterization โ one set of components for the gas cap, and another set for the oil rim. In order to track the net utilization of the injected lean gas, additional components are needed โ in this case one more component representing the lean gas, as the injected gas is a dry gas. The results of the comprehensive comparison demonstrate very clearly that these two approaches yield consistent condensate allocation and gas utilization results over the entire life of field (including history match and prediction). For condensate allocation, the hydrocarbon liquid production split depends on how the injected lean gas is tracked. For gas utilization, the injected lean gas must be tracked as a distinct component separate from both oil rim and gas cap components. The comparison also shows that although the tracer-based approach is numerically more efficient with less runtime, the full component tracking approach is simulator agnostic, and therefore can be implemented in any reservoir simulator. In addition, the full component tracking method can be used for cases where injection gas is a known mixture of oil rim and gas cap gas โ something the tracer-based option cannot handle. In summary, this paper presents a first comprehensive comparison of the two (2) different fluid tracking modeling approaches, with practical recommendations on modeling-based hydrocarbon liquid production and injection gas utilization allocation in cases where the commercial framework makes such allocation necessary.
- North America > United States (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.71)
- North America > United States > Wyoming > Rim Field (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.97)
Optimizing Perforating Strategy with Side Mounted Gun System for Auto Gas Lift Application with Smart Completions, Offshore Malaysia
Chung, Yvonne (Sarawak Shell Berhad) | Sandhu, Harwinder (Sarawak Shell Berhad) | Idris, Mohd Syahiran (Halliburton Energy Services) | Thien, Ronny Vui (Halliburton Energy Services) | Mohd Nazir, Amir Faiz (Halliburton Energy Services) | Ramamurthy, Subramaniam (Halliburton Energy Services)
Abstract This paper presents a state-of-the-art, automated gas lifted smart completion design, installed safely using Side Mounted Guns (SMG) to reduce well control risks for a carbonate field in Sarawak with a dominant threat of karst losses. It demonstrates how an SMG system was used to decrease installation time and minimize formation damage. The new 3D finite element software technique represents a step change in the ability to predict shock loading from complicated perforating systems and the subsequent effect on downhole completion components. Several challenges were addressed at the planning phase of the project, including the use of a new 3D finite element software to evaluate dynamic perforating shock loading and determine the optimal distance to safely place the key completion components in the well. A variety of system integration tests (SITs) were also introduced to verify compatibility of the SMG system in highly deviated well conditions and deploying through casing with inner diameter changes. Three wells have been successfully perforated with a long tubing-conveyed SMG system along with the smart well completion components, such as an inflow control valve (ICV), downhole pressure gauges, and seal assembly, which were then tested as fully functional after the gun detonation. During the well cleanup operation, the perforated gas cap was successfully used to lift the oil from the reservoir underneath the gas cap as an in-situ gas lift.
- Asia > Malaysia (0.50)
- Asia > Middle East (0.47)
Abstract Objectives/Scope Recently Abu Dhabi National Oil Company has called Whitson (PERA), a world leading PVT modelling consultancy company, to develop a best practice methodology/tool to quantify the condensate liquid production originating from the gas cap that is produced through oil rim producers' wells. This practice is integrating simulation work with field measured data and provided for the first time a solution to an oil and gas industry challenge, which is causing a conflict of interest between shareholders especially when oil rim and the associated gas cap are belonging to different concessions. Methods, Procedures, Process The work has been done for a giant oil field with large gas cap (rich in condensate) where only the oil is being developed since the 1960s. Initially the production GOR was limited to RS, but in 2010 the development strategy changed, and the field was being produced at GOR higher than RS allowing free gas from Gas Cap (rich with condensate) to be produced with oil. The question then arised of how much condensate is being produced through the oil rim producers. The condensate allocation method makes use of all measured well test data (Qo, GOR and API) and compositional reservoir simulation results. The used EOS (equation of state) model has been tuned to all available laboratory PVT data. This method uses a history-matched, reservoir simulation model run with a "dual-EOS" that is constructed by duplicating the tuned EOS model into two identical EOS models - one for the initial gas cap, and the other one for the initial oil zone. The dual- EOS run gives identical performance to single EOS model run. The generated dual-EOS compositional wellstreams are adjusted (1) to honor exactly the historical well test GOR data for each well, and (2) to honor as best possible the historical well test APIs for each well. The resulting wellstream will honor exactly the simulation model oil rates of each well throughout history, exactly the measured well test GOR, and close-to-exact APIs for each well. The final altered well streams are processed through a 4-stage field separator, yielding the well total stock-tank oil and condensate volumes. Results, Observations, Conclusions Historical gas cap condensate volumes produced from wells completed in the oil rim has been achieved during the field history. This was made possible by using (1) well production test data (GORs and APIs), (2) results from a history-matched compositional model, (3) tracking of components originally found in gas cap and in oil rim, and (4) application of a tuned EOS model. The conclusion is that such an integrated approach will result in a consistent and quantitatively accurate volume of condensate production volumes. Novel/Additive Information An innovative quantitative approach to the accurate estimation of condensate volumes originating in the gas cap - but produced from wells completed in the oil rim zone - has been developed and validated and could be applied for other fields, in addition it is fully flexible for future enhancements if needed. This methodology will definitely save time and unnecessary discussion and will provide more consistent results that will lead to more consensus from different parties.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.36)
Abstract This study elaborates the evolving techniques implemented to address challenge of thin oil rim (5 to 10-ft) development in relatively thick reservoir-Z (90-ft thickness). The issues are related to the presence of gas cap, active bottom aquifer, and presence of high permeability streak at the top 4-6 ft. of reservoir layer. Thin dense layer (1-2 ft.) present inside the high-K streak and underneath the layer, reservoir properties drop significantly (ca. 2-permeability order). Log signature markedly influenced by the rock property contrast and unable to differentiate fluid types. The oil-water contact varies between wells, driven more by the rock-type contrast rather than structural/depth position. Horizontal wells are implemented and deliver sustainable oil production for all reservoirs in the field except for the Reservoir-Z. Due to its complexity, no horizontal wells drilled in the early production scheme (EPS) delivered any oil from the respective reservoir. The wells were mis-placed at either gas cap and/or aquifer leg. The subsequent development implemented cased and perforated completion with 60deg. inclination along reservoir interval to overcome well placement challenge. These wells delivered sub-optimal result due to high-drawdown (limited entry of perforated interval) and suffered from early gas and water breakthrough. Accordingly, well configuration is improved by having 85deg. inclination along reservoir section. It lengthens oil column penetration and facilitate longer perforation interval but inefficient due to the long-wasted interval inside the transition zone. Ultimately, in perspective of efficiency, an ambitious goal was set to drill horizontal wells along the peripheral oil rim. Materializing the goal practically left no room for error in well placement. Meanwhile, the field has cluster-based drilling, implying long step-out/ departure and some degree of wellbore survey uncertainty (1ฯ of trajectory uncertainty ca. 30 ft.). A comprehensive program was prepared to tackle the challenges. This subsume: Feasibility evaluation of deep azimuthal resistivity tool usage (forward model). Pilot hole and relevant data acquisition (fluid analyzer/sampling). Update of deep azimuthal resistivity forward model with the pilot hole result. Geosteering and risk mitigation plan. The pilot hole result met its very objective, i.e.: delineating the areal outline of GOC around the horizontal target location and provide the exact stratigraphic target for horizontal well placement. It is 2-3 ft TST target below thin dense act as baffle toward high-K streak layer. Below this stratigraphic target, water saturation (Sw) increases abruptly above 45%. The deep azimuthal and at-bit resistivity tool was used to geosteer the well and successfully delivered 2000 ft. section of dry oil without any crossing to the high-K layer. After the failure of the early horizontal wells, it becomes dogma that placing horizontal section along oil column of reservoir-Z and at the same time avoiding the high-K streak as an impossible feat. The success proves otherwise and opens a wide door of alternative development scheme with huge cost-saving potential.
- Geology > Geological Subdiscipline > Stratigraphy (0.69)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.47)
- Geology > Sedimentary Geology > Depositional Environment (0.46)
Abstract Conventional strategy for developing of giant oil reservoirs with a gas cap involves an optimal production from the oil column before the gas cap is blown down. This paper investigates technical aspects of co-development strategies where demand for the gas may entail earlier exploitation of the gas cap along with the existing oil column development. Co-development of giant reservoirs with condensate-rich gas cap are particularly challenging due to the presence of significant condensate volumes. The basic strategy of the co-development plan involves producing from a gas cap first under full gas recycling so as to accelerate condensate recovery. This is followed by sales gas production by means of partial gas recycling in conjunction with water injection at gas-oil contact for pressure maintenance purposes. The injection of water at gas-oil contact is intended to provide a water barrier or fence that separates and / or minimize gas cap expansion toward oil. The degree at which sales gas is produced is under pressure maintenance scheme is thus linked to the level of the partial gas recycling and the efficiency of the barrier or fence water injection. To explore the feasibility of this process, reservoir simulations of mechanistic models were first used to study the reservoir physics of water injection at gas-oil contact for the purpose creating water barrier and /or fence. This was followed by implementation of the co-development scheme using sector models that represent two giant carbonate gas cap reservoirs. The feasibility and merits of the co-development strategy were measured by performance metrics that include condensate recovery, sales gas production, minimum oil loss and fluid migration at gas-oil contact and overall water demand. The results show that partial recycling along with barrier water injection may provide a mechanism for concurrent gas cap and oil column exploitation. A key factor that underlies the success of the co-development plan is the ability of the water injection at gas-oil contact to recover potential pressure drop in time as gas recycling ratio is reduced by forming effective barrier. This, in turn depends mainly on the reservoir geology and water injection volume and scheme. Moreover, reservoir characteristics that are favorable to the process are lower formation dip angle, smaller surface area at fluid contact and good injectivity of the reservoir rock.
- North America > United States (0.47)
- North America > Canada > Alberta (0.47)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
- Geology > Geological Subdiscipline > Stratigraphy (0.49)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.48)
- North America > United States > Colorado > Adena Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Greater Peace River High Basin > Belloy Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Kaybob Beaverhill Lake Field > Kaybob South Field > Swan Hills Formation > 1976082 Kaybobs 10-12-62-20 Well (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Kaybob Beaverhill Lake Field > Kaybob South Field > Duvernay Formation > 1976082 Kaybobs 10-12-62-20 Well (0.99)
Integration of Engineering Approaches and Workflows for an Economically Attractive Redevelopment of Highly Depleted Oil Rim Reservoirs - Giant Abu Dhabi Onshore Field
Meziani, Said (ADNOC) | Ghorayeb, Kassem (American University of Beirut) | Al Zaabi, Najla (ADNOC) | Hafez, Hafez (ADNOC) | Al Katheeri, Abdulla (ADNOC) | Maldonado, Jorge (Schlumberger) | Khattak, Iftikhar (Schlumberger) | Haryanto, Elin (Schlumberger) | Chabernaud, Thierry (Schlumberger) | Yersaiyn, Saltanat (Schlumberger) | Kumar, Sayani (Schlumberger) | Shahid, Shawwal (Schlumberger) | Agam, Abdelrahman (Schlumberger) | Shah, Abdur Rahman (Schlumberger) | Chakraborty, Subrata (Schlumberger)
Abstract This paper describes a pragmatic approach for reviving a highly depleted major Oil Rim Reservoir after more than 30 years of massive gas cap exploitation. The main objective is to assess options and identify the optimal plan to re-develop the Oil Rim while honoring and not jeopardizing the gas and condensate production of the network and the existing facility constraints. An integrated workflow was designed and implemented to understand the reservoir geology, field production history and to address requirements of both oil rim and gas cap developments. Analysis started by a dynamic synthesis to track oil/water contact (OWC) and gas/oil contact evolution with time using available surveillance data: MDT pressure gradient analysis with petrophysical evaluation (RST & OH logs). A study consisting of a comprehensive review and update of the static and dynamic models was carried out to ensure the model adequacy for robust re-development planning. The dynamic model quality was assessed by comparing dynamic model results with surveillance data especially with regard to predicting the contacts movements and pressure variation vs. time in the different regions of the Oil Rim. Production forecasting and optimal re-development plan identification followed a systematic approach aiming at assessing the incremental impact on oil recovery through the utilization of artificial lifting, different types of wells and completion as well as a variety of water injection scenarios. Sensitivity analysis included horizontal well lengths, well density, well placement, water injection and production capacity as well as economic constraints. Oil production from this low-pressure oil rim reservoir has been a challenge due to the spread oil resources and complicated production mechanisms. The movement of OWC and GOC has been very sensitive and caused unfavorable early water/gas breakthrough. Despite the low recovery factor, some attempts to revive dead oil wells through artificial lift means (ESP, booster pumps) were made and considered as an initial step to reactivate the inactive wells. The low oil production volume and hence low recovery makes the oil rim re-development economically less attractive. However, integration of state-of-the-art engineering approaches, proposed innovative technical initiatives and new technologies create an opportunity for significantly more economically attractive re-development. The workflows used and discussed in this paper were tested for four other oil rim reservoirs and can be implemented in similar challenging oil rim development projects.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.55)
- Europe > Hungary > Algyo Field (0.99)
- Africa > Middle East > Egypt > Western Desert > Kareem Field (0.99)
Scoping Model Study of Carbon Capture and Storage for Enhanced Oil Recovery for the Zarrarah Oil Field in UAE
Mheibesh, Yazan Ghassan (King Fahd University of Petroleum & Minerals) | Fraim, Michael (King Fahd University of Petroleum & Minerals) | Sultan, Abdullah S (King Fahd University of Petroleum & Minerals) | Al Shehri, Fahad Hassan (King Fahd University of Petroleum & Minerals)
Abstract The purpose of this scoping model study of Zarrarah field, with ~14 BSTB, and ~30 TSCF OIIP and GIIP respectively, was to show that natural gas cap could be used in a zero emission power plant to generate electricity, produce NGLs, and capture carbon dioxide gas. Over the lifetime of the project, the injected CO2 gas will displace the oil column in the heterogeneous carbonate rock system in a miscible gravity dominate mode. Petrophysical data needed to construct a simulation model for Zarrarh field was collected from literature review. We used 12 analogous rock types from neighboring fields of Asab and Bu Hasa. The CMG-GEM reservoir model used 18 components to describe the fluid properties and to verify no asphaltene drop out near the producing well bore. The model was calibrated on total field oil production and gas oil ratio and then various CO2 flooding scenarios were tested to optimize recovery and minimize gas coning in the horizontal well flooding patterns. The current production method for Zarrarah field is gas cap expansion with recycling of lean methane gas into the gas cap for pressure maintenance and recovery of NGLs. The averaged over the heterogeneous rock type regions, the miscible CO2 flood recovered at least 20% additional oil for each reservoir sector. The percentage of produced NGLs from the total in place will increase from 23% to 36% over the lifetime of the project with CO2 extraction. This production method will also supply for UAE and KSA at least 20 GW of zero emissions electric power for the next thirty years. CO2 reduces the oil viscosity and reduces gas coning by swelling the oil in the natural fractures system. The optimal CO2 injection technique is flank injection starting at the northern end of Zarrarah field. At the end of project life, the CO2 gas reserves should approach 30 TSCF to flood other reservoirs in the Empty Quarter such as Shah oil field. The novelty of this work is designing the first economic and zero emission power plant for EOR in KSA and UAE. Generating the first economic man-made CO2 storage reservoir for future miscible oil recovery in the Empty Quarter. The increased NGL recovery will help supply the feed stock for the petrochemical industry for the next 30 years. This technique has also the ability of providing a fresh water source for low salinity water flooding or local inhabitants.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.74)
- Asia > Middle East > UAE > Abu Dhabi > Rub' al Khali Basin > Zarrarah Field > Thamama Group Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Rub' al Khali Basin > Shah Field > Thamama Group Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Rub' al Khali Governorate > Rub' al Khali Basin > Shaybah Field (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.91)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Driving Reservoir Modelling Beyond the Limits for a Giant Fractured Carbonate Field - Solving the Puzzle
Spagnuolo, M.. (Eni S.p.A.) | Scalise, F.. (Eni S.p.A.) | Leoni, G.. (Eni S.p.A.) | Bigoni, F.. (Eni S.p.A.) | Contento, F. M. (Eni S.p.A.) | Diatto, P.. (Eni S.p.A.) | Francesconi, A.. (Eni S.p.A.) | Cominelli, A.. (Eni S.p.A.) | Osculati, L.. (Eni S.p.A.)
Abstract In this work, we address the challenge of modelling a complex, carbonate reservoir, where the fractures network, connected throughout a complex fault framework, represents large part of both the storage and the flow capacity of the system. The asset is a giant, onshore field, developed since the 90's by primary depletion through several horizontal wells, targeting anomalous fluid columns. Different culminations are characterized by specific production drive mechanisms. The objective is to integrate an impressive amount of data into a digital model, suitable to understand fluid flow behavior and support decision. The field is challenging in every geological and dynamic feature. The reservoir complexity ranges from the intricate structural framework (several hundreds of reverse faults), to the puzzling fractures network at different scales, to the unclear role of the low-porosity rock matrix, to the heterogeneous distribution - both laterally and vertically - of fluid properties, related to different combinations of hydrocarbon and acid components. The workflow is based on the adoption of Volume Based Modelling (VBM) to account for seismic faults. Then, large-scale fractures are modelled using a blend of stochastic and deterministic Discrete Fracture Networks (DFNs), while background fractures (BGF) are characterized using a Continuous Fracture Modeling (CFM) formulation. A Dual Porosity - Dual Permeability (DPDK) approach is then implemented for reservoir simulation. The model is finally reconciled with the production data by iterating between geology and simulated dynamic response. The whole modeling and simulation workflow, from static to dynamic model definition, is developed relying on company's top-class computational resources. The DPDK formulation, where DFN is the second medium while the first medium consists of BGF and rock matrix, allows us to simulate the main production mechanism: large-scale discontinuities โ DFN โ are withdrawal first, and then fluid is recharged by smaller scale features. Besides, the history matching phase, together with accurate production and Pressure-Volume-Temperature (PVT) data analysis, sheds light on the extreme heterogeneity of the field. Petrophysical properties, storage and effective apertures of discontinuities are calibrated according to the production history, and integrated into a comprehensive understanding of the reservoir. Eventually, we reveal how a robust history matched model may be used as a powerful tool to understand the impact of all the involved criticalities on the subsurface fluid behavior and movement in a complex fractured carbonate setting. The challenges addressed in this work provide relevant best practices for carbonate reservoir modelling, in particular highlighting the role of the integration between geology and reservoir engineering to minimize subsurface uncertainties. Furthermore, the PVT model developed in this study proposes new migration scenarios to explain the sour gas distribution. Finally, optimized procedures to tackle numerical criticalities using advanced reservoir simulators are disclosed.
- North America > United States (0.46)
- Asia > Middle East > UAE (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.94)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Reverse Fault (0.34)
- Geophysics > Seismic Surveying (0.90)
- Geophysics > Borehole Geophysics (0.69)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- (3 more...)
Abstract A numerical simulation study was conducted to explore feasibility of gas cap and oil column co-development plans. Unlike conventional development schemes that entail to optimally produce first from oil column while deferring gas cap development, the co-development strategy studied here involves simultaneous production from oil column and gas cap. The drive mechanism consists of down-dip peripheral water injection for oil column in conjunction with barrier water injection at or near gas-oil contact that is designed to separate the gas cap from the oil column and thereby facilitate gas production. The basic objective of the study is twofold: to assess the merits of the concept of barrier water injection and to identify key subsurface and operational parameters that have most significant impact on oil and gas recovery. Extensive numerical simulations were conducted to explore the conditions under which the concept of barrier water injection is favourable as a recovery process. Important issues related to the viability of the development concept are how fast a barrier water can be established, how long it can be sustained and how many wells are needed. Furthermore, effects of gas cap relative size, reservoir geometry (e.g., dip-angle and surface area of the gas-oil contact), trapped gas, rock heterogeneity and off-take rates have been investigated in detail. The work shows that the feasibility of the co-development scheme is mainly controlled by pressure maintenance and balance of injection, relative size of gas cap, reservoir geometry and rock heterogeneity.
- Europe (1.00)
- North America > United States > Colorado (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.16)
- Geology > Geological Subdiscipline (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 359 > Mahogany Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 349 > Mahogany Field (0.99)
- North America > United States > Colorado > Adena Field (0.99)
- (3 more...)