Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Sizing Gelant Treatment for Conformance Control in Hydraulically-Fractured Horizontal Wells
Liang, Bin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Jiang, Hanqiao (China University of Petroleum, Beijing) | Li, Junjian (China University of Petroleum, Beijing) | Li, Min (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lan, Yuzheng (University of Texas at Austin) | Seright, Randall (New Mexico Petroleum Recovery Research Center)
Abstract Horizontal wells are subject to water breakthrough problems caused by natural or hydraulic fracture connections. Treatment with gelant normally is an effective choice. However, at present, no methods can provide quantitative guidance for designing gelant treatment in fractured horizontal wells. In this paper, we proposed a fracture-conductivity-based analytical model to guide sizing gelant treatment in hydraulically fractured horizontal wells. It includes the evaluation of fracture number intersected with the horizontal well, calculation of gelant leakoff distance according to the desired water productivity reduction, and the method to determine optimal gelant volume. The principle for controlling gelant injection and the method for forecasting water shutoff performance are also included. The successful application is based on two requirements: (1) gelant can penetrate a short distance from fracture surface into adjacent matrices; and (2) gelant or gel can reduce permeability to water more than to hydrocarbon. Finally, we summarize a 9-step procedure for sizing gelant treatment in fractured horizontal wells. This work provides quantitative guidance for water shutoff treatment using cross-linked polymer gels that create disproportionate permeability reduction.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Successful Field Implementation of CO2-Foam Injection for Conformance Enhancement in the EVGSAU Field in the Permian Basin
Katiyar, Amit (The Dow Chemical Company) | Hassanzadeh, Armin (The Dow Chemical Company) | Patil, Pramod (Rock-Oil Consulting Group) | Hand, Michael (ConocoPhillips) | Perozo, Alejandro (ConocoPhillips) | Pecore, Doug (ConocoPhillips) | Kalaei, Hosein (ConocoPhillips) | Nguyen, Quoc (The University of Texas at Austin)
Abstract This paper presents the performance of a CO2 foam injection pilot implemented in the East Vacuum Grayburg San Andres Unit (EVGSAU) by ConocoPhillips in cooperation with The Dow Chemical Company. The pilot project focuses on a single CO2 injection pattern, consisting of one injector and eight producers, selected due to signs of early gas breakthrough and poor overall sweep efficiency. To solve these conformance issues and increase overall pattern production performance, a new foaming surfactant with low adsorption and high gas partitioning characteristics was developed and experimentally tested at simulated reservoir conditions. A "water alternating surfactant-in-gas" injection strategy was created utilizing a history matched reservoir simulation model and an empirical foam model. This reservoir model was also utilized to better understand the dependency of surfactant concentration on foam generation and fluid diversion. Injection profile logs (IPLs) were also run, in both water and CO2 phases, prior to pilot implementation to establish baseline injection performance. This paper will detail several performance indicators that illustrate sustained improvement in pattern injection and production after more than 15 cycles of alternating water, CO2+surfactant, and CO2-only injection. During each cycle, gas injectivity trends were calculated and compared to the baseline to monitor foam strength and performance. Four additional IPLs were run, which indicated continuous improvement in vertical sweep efficiency and ultimately resulted in uniform injection distribution between the upper and lower sections of the producing zone. Finally, the most significant result of the trial was the uplift in pattern oil production. It has averaged ~20% above the baseline production forecast throughout the entire pilot period and peaked within the first six months at ~60% above the baseline. The success of this pilot illustrates the benefits of using a low adsorbing and CO2 soluble foaming surfactant to address reservoir conformance issues for CO2 floods. Further optimization of the pilot based on the simulation forecast is planned to improve long-term pilot economics.
- North America > United States > New Mexico (1.00)
- North America > United States > Texas (0.82)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (42 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract To date, feasibility studies of the Gas and Downhole Water Sink-Assisted Gravity Drainage (GDWS-AGD) process for the South Rumaila oil field have considered using Carbon Dioxide gas injection to enhance oil recovery. As availibility of CO2 is limited and its cost considerable it might be also feasible to use natural gasAssociated Produced Gas (APG), that has been recently tested as an alternative solvent to enhance oil recovery. The paper reports on a simulated comparison of the APG or CO2 application in the South Rumaila oil field. The comparison metrics include field recovery factor, water cut in oil and water producers, Gas Oil Ratio in oil producers, cumulative gas injection, and average saturation. In the study, the GDWS-AGD process installation comprises 20 vertical APG injection wells completed at the top of the reservoir to build a gas cap in the oil pay zone. In addition, eleven horizontal oil-producing wells are placed at the bottom of the oil pay zone with six horizontal water drainage (sink) wells below the oil-water contact (OWC). The two horizontal leg installation may be made from a vertical well with 7-casing dual-completed (from two kick-off points) in the oil payzone and in the bottom water (below OWC) with two horizontal well legs and the two 2-3/8 inch tubings in each well. In a dual-tubing design of the process the two horizontal well legs produce independently. If only one tubing is used production from the water sink well is hydraulically isolated inside the vertical well by a packer. In either design, the water sink well is operated with a submersible pump. In this study, the GDWS-AGD process with APG is considered for the upper sandstone member/South Rumaila Oil Field, located in Iraq to improve oil recovery. The Rumaila field has an infinite acting-aquifer with very strong edge water drive. In the GDWS-AGD, the bottom water drainage would not only reduce water cut and water cresting, but would also significantly reduce the reservoir pressure, resulting in improving gas injectivity by significantly reducing the need for high injection pressure and gas solubility will be also reduced in the immiscible mode. Significant improvement with the GDWS-AGD process - oil recovery increased from 76.5% by CO2 to 82.5% by APG and water cut was readily controlled resulting in more rapid reduction with APG (from 95% to less than 5%) than that with CO2 in all horizontal oil producers. The results show that the use of APG alternative to CO2 for the GDWS-AGD process not only improves water-cresting and controls water cut, but also enhances gas injectivity and significantly improves oil recovery.
Abstract Thanks to the advancements in and convergent of the two technologies of horizontal well drilling and hydraulic fracturing, the oil production from tight formations has become possible and economic. While hydraulically fractured horizontals wells (HFHW) have increased the productivity of these reservoirs, these wells typically see a sharp decline in hydrocarbon rate due to tight nature of these reservoirs. Operators have improved oil recovery methods in these formations with the successful application of the secondary recovery method of waterflooding. This combination of HFHW and waterflooding has primarily been implemented in Canadian tight oil formations such as the Canadian Bakken Shale, lower Shaunavon, Viking, Belly River and Cardium. With the application of waterflooding on these HFHW, the one issue that operators are facing is the management of quick water breakthrough due to well to well communication through the network of induced or natural fractures resulting in poor sweep efficiency of waterfloods. Conformance improvement using polymer gel technology, a polymer and a polymer specific cross-linker, has been a common practice in conventional assets for 30 years. The polymer solution is mixed with the crosslinker on the surface and the mixture becomes more viscous (due to the reaction between polymer and crosslinker) as it is pumped downhole and into the reservoir. The application of polymer gel technology in unconventional tight oil water floods requires a new approach and is most successful when approached in a systematic way starting with proper diagnosis and candidate selection followed by engineering design and field execution. After candidate selection and diagnosis of communication between wells, a treatment design is put together based on the level of communication as measured by the transit time between the two wells. The conformance treatment is implemented by bull heading the mixture of polymer and crosslinker and sequentially increasing the gel strength by increasing polymer concentration at fixed polymer to crosslinker ratio. The idea is to build pressure continuously throughout the treatment, an indication of polymer gel filling up the path of communication. A new application for gel conformance technology, in tight oil waterfloods, as a cost-effective solution, to address the well to well communication and improve sweep efficiency is discussed in this article. Relatively smaller size and lower strength of gel, compared to the typical applications, makes the application of polymer gel in HFHWs unique and very effective. This paper will review multiple campaigns in Canadian Bakken from 2016 to 2018 and discuss the rate of success, incremental oil produced and longevity of these treatment. Opportunities to further optimize these treatments and the pitfalls have been recognized and discussed.
- North America > United States > South Dakota (0.34)
- North America > United States > North Dakota (0.34)
- North America > United States > Montana (0.34)
- North America > Canada > Saskatchewan (0.28)
- North America > United States > Wyoming > Wertz Field (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
Improving CO2 Vertical Sweep Efficiency in Tinsley Field with Dedicated Injectors
Sheikha, Hussain (Denbury Resources Inc.) | Blackmer, Scott Mitchell (Denbury Resources Inc.) | Sharaf, Essam (Denbury Resources Inc. & Geology Department, Faculty of Science, Mansoura University) | Marks, Dustin (Denbury Resources Inc.)
Abstract Lower oil production rate, conformance, and poor sweep efficiency are major concerns in an enhanced oil recovery (EOR) flood when implemented across multiple intervals. Oil recovery and flood performance in reservoirs with multiple lobes characterized by heterogeneous rock properties suffer greatly when the lobes are commingled. Tinsley Field is a reservoir with two distinct lobes. Initial development of the EOR flood commenced by commingling injection in the same wellbore and production from the two lobes to decrease the capital cost and boost oil production. Reservoir management of the CO2 flood indicated good sweep was taking place in one lobe. Concerns about the possibility of early breakthrough of CO2 in the dominate lobe, leaving stranded oil in the other lobe, prompted the initiation of a dedicated injection program. Early breakthrough could lead to filling up our compressors more quickly than anticipated, which could increase our capital requirements. Dedicated injection into individual lobes was initiated to improve the sweep efficiency. The team devised a methodology to select prospective wells and quantify the feasibility of adding new dedicated injectors in some of the existing patterns at Tinsley field. The methodology utilized a combination of geological cross sections to identify areas that are characterized by two lobes separated by a shale barrier or baffle, injection profiles to identify the current CO2 allocation, and an estimation of remaining oil in place. A sector model was constructed to simulate the recovery process and aid in understanding the impact of dedicated injection on oil production rate and recovery from individual lobes. The study revealed that only two of the three fault blocks can be characterized with an upper and lower lobe. Within those two fault blocks, several producers were identified as having poor conformance with a high remaining oil in place. Numerical results of the simulation model show that without dedicated injectors, the two lobes will be flooded at two different injection rates leaving substantial oil unrecovered because of the different injectivity of each zone. Candidate dedicated injectors were selected and ranked for execution based on our methodology. The early results from the dedicated injection program indicate it will lead to a higher recovery factor in the lower lobe because of dedicated injection into the lower lobe resulting in higher processing rate of CO2. The methodology presented in this paper provides a logical workflow that can identify areas with stranded oil in a reservoir with multiple zones. Following this process could lead to opportunities to drill dedicated injectors to improve oil production rate, conformance, and recovery factor.
- North America > United States > Mississippi > Yazoo County (1.00)
- North America > United States > Texas (0.93)
- Geology > Geological Subdiscipline (0.88)
- Geology > Structural Geology (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- South America > Venezuela > Anzoátegui > Eastern Venezuela Basin > Maturin Basin > Santa Rosa Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (36 more...)
Abstract Recent studies have shown that enhanced oil recovery will be the focal point for approximately 50% of the global oil production in the upcoming two-three decades. According to the several ballpark studies conducted on EOR techniques, results show that for reservoirs with oil viscosities ranging from 10 to 150 m Pa.s., polymer flooding seems to be an ideal development strategy. However, when the oil viscosities exceed 150 m Pa.s., polymer injectivity and pumping efficiencies can turn out to be major inhibiting factors, thereby limiting the range of oil viscosities for which polymer flooding can be utilized. The core reason for this is that the values of viscosity for the injected water containing polymer, calculated for the beneficial mobility ratio, can lead to the inhibiting factor stated above. Previously conducted lab studies have shown that supramolecular systems are very resistant in high temperature - high salinity systems. To be able to achieve the easier injection, the injected supramolecular viscosity will be kept at lower values and then increased to the levels right before or upon contacting the oil in the reservoir. The core difference between conventional polymer systems and supramolecular polymer systems is that the latter disassemble and re-assemble as opposed to degradation when exposed to extreme shear stress and temperatures. It can therefore be said that supramolecular polymer systems are self-healing in nature. The phenomenon has been observed in cases where polymers with high molecular weight are forced through narrow flow channels. Though molecular division takes place, supramolecular systems have shown a tendency of reassembly later on. Therefore, adaptability of these systems to bounded or restricted environments can be established. This study will add the modeling and simulation components of supramolecular systems which can be effectively utilized in high temperature-high salinity conditions through adjustments to viscosities and interfacial properties of these assemblies. This will help compare the displacement efficiency of supramolecular systems which efficiently perform in a wide range of reservoirs such as thin zones, and reservoirs within permafrost conditions. This can significantly benefit the oil and gas companies worldwide in preparing a technically feasible, but also, a cost effective EOR development strategy, whenever polymer injection is of consideration.
- North America > United States (1.00)
- Asia > Middle East > UAE (0.28)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
Abstract The Gas and Downhole Water Sink-Assisted Gravity Drainage (GDWS-AGD) process has been developed to overcome of the limitations of Gas flooding processes in reservoir with strong aquifers. These limitations include high levels of water cut and high tendency of water coning. The GDWS-AGD process minimizes the water cut in oil production wells, improve gas injectivity, and further enhance the recovery of bypassed oil, especially in reservoirs with strong water coning tendencies. The GDWS-AGD process conceptually states installing two 7 inch production casings bi-laterally and completing by two 2-3/8 inch horizontal tubings: oil producer above the oil-water contact (OWC) and one underneath OWC for water sink drainage. The two completions are hydraulically isolated by a packer inside the casing. The water sink completion is produced with a submersible pump that prevents the water from breaking through the oil column and getting into the horizontal oil-producing perforations. The GDWS-AGD process was evaluated to enhance oil recovery in the heterogeneous upper sandstone pay in South Rumaila Oil field, which has an infinite active aquifer with a huge edge water drive. A compositional reservoir flow model was adopted for the CO2 flooding simulation and optimization of the GDWS-AGD process. Design of Experiments (DoE) and proxy metamodeling were integrated to determine the optimal operational decision parameters that affect the GDWS-AGD process performance: maximum injection rate and pressure in injection wells, maximum oil rate and minimum bottom hole pressure in production wells, and maximum water rates and minimum bottom hole pressure in the water sink wells. More specifically, Latin hypercube sampling and radial basis neural networks were used for the optimization of the GDWS-AGD process performance and to build the proxy model, respectively. In the GDWS-AGD process results, the water cut and coning tendency were significantly reduced along with the reservoir pressure. That resulted to improve gas injectivity and increase oil recovery. Further improvement in oil recovery was achieved by the DoE optimization after determining the optimal set of operational decision factors that constrains the oil and water production with gas injection. The advantage of GDWS-AGD process comes from its potential feasibility to enhance oil recovery while reducing water coning, water cut, and improving gas injectivity. That gives another privilege for the GDWSAGD process to reach significant improvement in oil recovery in comparison to other gas injection processes, such as the Gas-Assisted Gravity Drainage (GAGD) process, particularly in reservoirs with strong water aquifers.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > Iraq > Basra Governorate (0.50)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.49)
- Asia > Middle East > Saudi Arabia > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Zuluf Field > Wasia Formation (0.99)
- Asia > Middle East > Saudi Arabia > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Zuluf Field > Shu′aiba Formation (0.99)
- Asia > Middle East > Saudi Arabia > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Zuluf Field > Khafji Formation (0.99)
- (8 more...)
Abstract Injection of blocking gels in the near wellbore of producer wells is a technique employed for water production control. A proven and effective alternative to control this water excess is the application of crosslinked gels. Water shut-off (WSO) treatments efficiency depends on several aspects such as reservoir fluid flow patterns, rock petrophysics, formation heterogeneities and gel characteristics. Although experimental laboratory tests previous field implementation, are many times underestimated, they provide valuable information that increases the chances of success. Integrating lab results with reservoir and field data creates a proper scenario that diminishes the uncertainties during field implementation. It is also crucial the support of a multidisciplinary team work while injecting the WSO tretament. This paper presents a successful water shut-off treatment specially designed for high temperature, applied in a production well located in Vizcacheras field, Mendoza Agentina.
Abstract This paper summarizes BP's Alaskan viscous oil resource appraisal strategy to de-risk viscous oil resource progression with a goal to improve recovery factor by 10%. A key to recovery improvement is application of improved oil recovery/enhanced oil recovery (IOR/EOR) methods. However, even after detailed studies, moving to the next stage including field pilots is not always easy in the mature and remote Alaskan North Slope. The paper also covers BP's Alaskan viscous oil technology strategy, extraction technologies selection, simulation and analytical studies, laboratory studies, and field trials for various shortlisted methods. A comprehensive study strategy conducted for progressing chemical EOR processes is discussed. The paper also addresses the challenges of obtaining new core and fluid samples for laboratory studies and logistical and economic considerations for field trials due to location and weather conditions in this part of the world.
- North America > Canada (0.68)
- Europe > United Kingdom (0.66)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.28)
- Geology > Mineral (0.93)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- North America > United States > Alaska > Schrader Bluff Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- (8 more...)
A Review of Responses of Bulk Gel Treatments in Injection Wells-Part I: Oil Production
Aldhaheri, Munqith (Missan Oil Company, Dept. of Petroleum Engineering, University of Misan) | Wei, Mingzhen (Missouri University of Science and Technology) | Zhang, Na (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Abstract As lifespan extenders, bulk gels have been widely applied to rejuvenate oil production from uneconomic producers in mature oilfields by improving sweep efficiency of IOR/EOR floodings. This paper presents a comprehensive review for the responses of injection-well gel treatments implemented between 1985 and 2014. The survey includes 61 field projects compiled from SPE papers and U.S. DOE reports. Seven parameters related to the oil production response were evaluated according to the reservoir lithology, formation type, and recovery process using the univariate analysis and stacked histograms. The interquartile range method was used to detect the under-performing and over-performing gel projects. Scatterplots were used to identify effects of the injected gel volume and the treatment timing on the treatment responses. Results indicated that gel treatments have very wide ranges of responses for injection and production wells and for oil and water rates/profiles. The typical incremental oil production is 116 MSTBO per treatment, 15 STBO per gel barrel, or 10 STBO per polymer pound. We identified that gel treatments perform more efficiently in carbonate than in sandstone reservoirs and in naturally-fractured formations than in other formation types. In addition, the incremental oil production considerably increases with the channeling strength and the injected gel volume for all formation types, not just for the matrix-rock reservoirs. Moreover, gel treatments applied in naturally-fractured formations have lower productivities in sandstones than in carbonates based on the normalized performance parameters. Declining tends were identified for all parameters of the oil production response with the treatment timing indicators. The sooner the gel treatment is applied; the faster the response and the larger the incremental oil production and its rate. It is recommended to allow longer evaluation times for gel treatments applied in matrix-rock formations or in mature polymer floodings as their response times may extend to several months. Gel treatments would perform more efficiently if they are conducted at water cuts <70%, flood lives <20 years, or recovery factors <35%. For different application environments, the present review provides reservoir engineers with updated ideas about what are the low, typical, and high performances of gel treatments when applied successfully and how other treatment aspects affect the performances.
- North America > United States > Wyoming (0.94)
- North America > United States > Texas (0.68)