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Collaborating Authors
Value of DTS in Multi-Stacked Reservoirs to Better Understand Injectivity and Water Flood Effectiveness – A Field Example from the UAE
Gomes, Jorge (Douglas Boyd and Sofiane Tahir, ADNOC Upstream) | Mason, Jane (Douglas Boyd and Sofiane Tahir, ADNOC Upstream) | Edmonstone, Graham (Douglas Boyd and Sofiane Tahir, ADNOC Upstream)
This paper highlights the application of downhole fiber optic (FO) distributed temperature sensing (DTS) measurements for well and reservoir management applications: 1) Wellbore water injectivity profiling. 2) Mapping of injection water movement in an underlying reservoir. The U.A.E. field in question is an elongated anticline containing several stacked carbonate oil bearing reservoirs (Figure 1). Reservoir A, where two DTS monitored, peripheral horizontal water injectors (Y-1 and Y-2) were drilled, is less developed and tighter than the immediately underlying, more prolific Reservoir B with 40 years of oil production and water injection history. Reservoirs A and B are of Lower Cretaceous age, limestone fabrics made up of several 4th order cycles, subdivided by several thin intra dense, 2-5 ft thick stylolitic intervals within the reservoir zones. Between Reservoir A and Reservoir B there is a dense limestone interval (30-50 ft), referred as dense layer in the Figure 1 well sections.
- Asia > Middle East > UAE (0.69)
- Europe (0.68)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Asia > Middle East > Saudi Arabia > Thamama Group Formation (0.97)
Abstract A major matured Malaysian offshore oilfield with more than 40 years of production history under a combination of moderate to strong aquifer support and moderate-size gas cap will be subjected to a unique enhanced oil recovery (EOR) scheme, the first of its kind offshore, called Gravity Assisted Simultaneous Water Alternating Gas (GASWAG) injection process. It is essentially a scheme which involves simultaneously injection of gas and water which involves injecting water up-dip and gas down-dip structurally in a depleted oil reservoir. This method takes the advantage of gravity drainage mechanism to maximize recovery from un-swept oil zones down-dip by aquifer influx and up-dip by gas cap expansion processes and it could be different than the conventional water alternating gas (WAG) method. This paper mostly presents the dynamic modelling and simulation work which has been established during this case study to obtain the GASWAG base case model and to conduct the optimization and sensitivity assessments on the major reservoir parameters. It also describes the main subsurface uncertainties and operational risks and their impact on incremental oil reserve and the results were used to design mitigation plans to help minimize impact on oil recovery volumes. Implementing the full field scale of this EOR scheme involves a detailed reservoir management plan (RMP) with many reactivations of idle wells, well workover plans, behind casing opportunities and adding perforation interval together with identified new infill wells to maximize the flood-front movement of the injected fluids. Obviously, good communication with field operational personnel is paramount to ensure these RMP are adhered to clear targets to successfully achieve the desired incremental recovery and will be elaborated in this paper. This paper describes the strategy and workflow to monitor and measure the two key success factors of this project which are production attainability and reserve attainability. The success of this project depends on continuous evaluation to check the actual performance against the anticipated behavior. As soon as new information obtains along implementation, it will be assessed against targets to steer the way to the main goal of additional reserve by the end of field life. Thus, it requires a comprehensive monitoring plan with detailed surveillance and data collection and, well testing to revisit and update the dynamic model accordingly. The results of this study show that GASWAG has emerged to be one of the most promising techniques with the highest incremental reserve for this field among various EOR techniques evaluated such as continuous gas injection, continuous water injection, conventional WAG, aquifer-assisted WAG, and double displacement.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.53)
- Asia > Malaysia > Sabah > South China Sea > Sabah Basin > Block SB301 > Samarang Field (0.99)
- Africa > Middle East > Egypt > Western Desert > Kareem Field (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- (2 more...)
Abstract The AX field is located in Deepwater Offshore Nigeria and has been in production for ca.12 years through FPSO with a waterflood scheme providing pressure maintenance and sweep for the reservoirs. Over the years, AX field has moved from the use of deviated frac-pack injectors to horizontal SAS injectors due to significant declining injectivity observed with the deviated injectors. The switch to horizontal injectors was premised on various studies proposing that horizontal water injectors in deep water are expected to have longer well life due to the larger flow area and ability to inject at lower flow velocities (matrix condition) compared to vertical water injectors. The benefits of going horizontal is further enhanced by keeping the well in Matrix mode for as long as possible before switching into frac mode. However, damage is inevitable afterwards, even for relatively clean injection water. This may be primarily due to various factors, one of which is fines influx into the well during abrupt shut-ins/trips from the FPSO. AX field started operating horizontal injectors since 2011. On the average, most horiziontal injectors in AX field begin to experience injectvty decline about 1 – 2 yrs after start of injection as was the case with AX9 injector. AX9 is a horizontal injector providing support to 2 producers in the field. Over the past four years injection had declined from 40 kbwpd to 21 kbwpd at 395 barg IBHP with II of 20 bpd/psi. This drop in the injectivity index led to a production curtailment of ca. 5 kbopd from the supported producers. From a cross learning opportunity, it was identified that there is higher possibility of success (POS) with stimulating horizontal water injectors while still in matrix mode. Leveraging on this knowledge we decided to attempt stimulating the AX9 well for better performance. Stimulation was carried out successfully under matrix condition using a deepwater rig in May 2018. Post stimulation, well was ramped up to 43 kbpwd at 330 barg IBHP. Increase of ca. 15 kbwpd with a corresponding 21% drop in BHP. Initial performance shows a four-fold improvement in injectivity index; current injectivity index is 80 – 100 bpd/psi. The success of the AX9 stimulation has validated early stimulation of injectors while still in matrix mode rather than later when the well would have switched to frac mode. Additionally, the acid recipe has opened opportunities to mitigating injectivity decline in deepwater water injectors.
Abstract This paper summarizes the design, operation, results, and reservoir modeling of a miscible hydrocarbon gas injection pilot using horizontal wells in the Fateh Mishrif, a large carbonate reservoir in an offshore operating environment.The pilot included a single horizontal water-alternating-gas (WAG) injector flanked by two horizontal producers drilled near the base of the reservoir.The three-well pattern was surrounded by four water injectors which provided confinement and pressure control.Produced gas from the field was used for injection without supplemental enrichment. The pilot began operations in 1997. Commencing in 1999, gas was injected in three cycles over a period of four years. A clear incremental oil rate response to the gas injection was first observed in early 2003, peaking with a 400% incremental oil rate increase from the two producers. Pilot results have been history matched with a compositional reservoir model to reconcile reservoir characterization interpretations and to provide prediction of ultimate recovery. Incremental recovery over waterflood operations is predicted to be 6% of original oil-in-place for 0.15 hydrocarbon pore volumes of gas injection. Introduction and Background Reservoir Characteristics. The Fateh Field is one of four Dubai Petroleum Company (DPC) operated fields and is located in 120 feet of water in the Arabian Gulf, 90 kms offshore Dubai, United Arab Emirates.Fateh Mishrif, the largest of the DPC-operated reservoirs, is found at a depth of 8300 ft-TVD subsea. It is a Middle Cretaceous-aged carbonate rudist grainstone shoal that has been uplifted by salt to form a four-way dipping anticline.The top of the anticline was eroded resulting in an unconformity against the Laffan shale, which provides stratigraphic seal on the trap.Structural dips are less than 10 degrees. The reservoir is moderately faulted and few faults offset the reservoir section. In general, faults do not appear to play a significant role in overall reservoir performance. The primary reservoir section averages 250 feet, pinches out updip as it approaches the erosional unconformity, and is subdivided into the Upper and Lower Mishrif.Porosity over the entire section is favorable and relatively uniform; however, permeabilities in the Upper Mishrif are 50 to 200 md while Lower Mishrif are less than 20 md.Diagnesis has enhanced permeability of the reservoir section directly beneath the unconformity. The reservoir was found normally pressured, highly undersaturated with a 33 API oil and solution gas-oil ratio less than 500 scf/bo.It also exhibits a tilted oil-water contact underlain by a tarmat. Development History. The reservoir was discovered in 1967, followed by development and first production in 1970.After four years of depletion and characterization of natural water influx for pressure support, a waterflood was installed.The waterflood pattern included several dip-aligned 3-well "spokes" and perperphial water injectors near the oil-water contact.The early design, operational issues, and predictions of the waterflood performance were previously published1.At that time, the predicted ultimate waterflood recovery was 34% of the original oil-in-place.With continued vertical and horizontal well infill drilling, higher-pressure water injection, and continuous waterflood and artificial lift optimization, ultimate secondary recovery is now expected to exceed 60% of the original oil-in-place. Currently, there are 60 producing and 60 water injection wells.The producing wells are gas lifted and total water injection is 380,000 bwpd. Enhanced Oil Recovery Projects. Enhanced oil recovery screening initiatives began in the late 1980s as the reservoir was approaching the end of the production plateau. Miscible hydrocarbon gas injection was selected as the most promising scheme.Two pilots have tested the concept: one using vertical wells followed by a second with horizontal wells.
- Geology > Geological Subdiscipline > Stratigraphy > Lithostratigraphy (0.65)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.44)
Abstract Carbon dioxide flooding has been recognized widely as one of the most effective enhanced oil recovery processes applicable to light to medium oil reservoirs. Moreover, the injection of CO2 into an oil reservoir is a promising technology for reducing greenhouse emissions while increasing the ultimate recovery of oil. Numerical reservoir simulation is an important and inexpensive tool for designing EOR CO2 projects and predicting optimal operational parameters. In this work, reservoir simulations performed with a compositional simulator were applied to investigate the macroscopic mechanisms of CO2 injection processes. Horizontal injectors were used to increase injectivity. Compared to traditional vertical wells, horizontal wells are more attractive to improve CO2 flooding economics by increasing injection rate, improving areal sweep and increasing CO2 storage. The effects of several important parameters on the performance of the CO2 process were studied to optimize the process. Operational parameters such as the primary production time, the injector pressure and length, injection time as well as production well pressure and different production schemes were investigated to determine the optimal operating conditions for simultaneous objectives of higher recovery and higher CO2 storage. The application of CO2 flooding using horizontal wells can shorten project life, which is critical to its economics. The simulation results served as the basic input parameters for the economic analysis performed. Furthermore, NPV (net present value) results were used to optimize the profitability of the project and to compare the CO2 application using vertical and horizontal wells. The analysis used actual design parameters, including equipment and operating costs similar to the ones associated with current ongoing projects. The evaluation emphasized the importance of reservoir characteristics, optimum design of operation parameters and economical factors in the economic feasibility of CO2 injection projects for enhanced oil recovery and sequestration. Introduction Carbon dioxide flooding process can increase oil recovery by means of swelling, evaporating and lowering oil viscosity. Many injection schemes using CO2 have been applied, including CO2 gas injection (continuously), CO2 gas slug followed by water, etc. Currently, atmospheric concentration of CO2 is raising increasingly concerns and different possibilities for CO2 sequestration are being studied, including CO2 storage in abandoned gas and oil fields. This paper studies CO2 flooding process using horizontal wells to simultaneously enhance recovery and increase CO2 storage. Obviously this is an economic and environmental issue which optimization will contribute to reach the two abovementioned objectives. Although usually specific economic, social, and environmental indicators should be studied systemically, this paper mainly focuses on the economic analysis of CO2 flooding and sequestration processes. Economic analysis is especially important in a CO2 flooding project because most of such projects have high investment and operating costs and low profit expectation. This paper studies the application of conventional CO2 miscible flooding process (continuous injection) using horizontal wells. Horizontal wells are become more cost effective with increasing productivity performance and decreasing drilling and completion costs. Comparison is made between schemes using vertica