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Results
Abstract Polymer flooding is now a well-recognised and mature technology to increase hydrocarbon recovery, used in many parts of the world. Given its success, operators are looking at new opportunities for polymer and are trying to push the technical barriers even further. One of these barriers is high salinity which is detrimental to the economics of polymer floods with standard polymers, and thus requires other solutions. Associative polymers are polyacrylamide-based polymers well known for their good resistance to high salinity due to their structure and as a result they could be very promising for use in fields with high TDS. However, they have so far seen little use in field applications due to their perceived plugging tendency, high permeability and mobility reduction which make them more adapted to near-wellbore treatment. Most if not all of the field projects involving associative polymers have taken place in China and in Canada, but little has been published so far. Since public information is available for the Canadian projects, the aim of this paper is to present the field experience of associative polymers in these Canadian projects. The paper will focus on presenting four field cases, Bodo, Mooney and Suffield (2), all in Western Canada. Bodo is a polymer flood while Mooney and Suffield are both polymer and alkali-surfactant polymer projects. Although public information is not always complete, what is available provides some useful and much needed insight on the performances of associative polymers in the field. Our analysis of these four field cases suggests that associative polymers can be injected without special difficulty provided they are well chosen, that is they need to be sufficiently associative to outperform HPAM but not too much in order not to plug the reservoir. These results should comfort engineers who have so far been reluctant to use associative polymers due to lack of field experience. Very few field cases of polymer flood involving associative polymers have been published so far and this paper attempts to shed some light on the performances of associative polymer in some unpublished projects. These positive results may incite engineers working on projects where associative polymers could find a use to consider them.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.71)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.46)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Suffield Block > Suffield Field > Aecog (E) F-4 Suff 7-27-17-5 Well (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Mooney Field > Bluesky Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Bluesky Formation (0.99)
- Africa > Nigeria > Gulf of Guinea > Rivers > Niger Delta > Niger Delta Basin > OML 11 > Bodo Field (0.99)
The Effect of Phase Distribution on Imbibition Mechanisms for Enhanced Oil Recovery in Tight Reservoirs
Wang, Mingyuan (The University of Texas at Austin) | Argüelles-Vivas, Francisco J. (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin)
Abstract The main objective of this research was to investigate the impact of initial water on the oil recovery from tight matrices through surfactant-enhanced water imbibition. Two flooding/soaking experiments using fractured tight cores with/without initial water were performed. The experimental results were analyzed by the material balance for components: oil, brine, and surfactant. The analysis resulted in a quantitative evaluation of the imbibed fraction of the injected components (brine and surfactant). Results show that the surfactant enhanced the brine imbibition into the matrix through wettability alteration. The initial efficiency of the surfactant imbibition increased when brine was initially present in the matrix. The imbibition of brine was more efficient with no initial water in the matrix. A possible reason is that the presence of initial water in the matrix was able to increase the initial efficiency of the surfactant imbibition; however, the increased amount of surfactant in the matrix lowered the interfacial tension between the aqueous and oleic phases; therefore, the efficiency of brine imbibition was reduced. Another possible reason is that capillary force was lower in the presence of initial water in the matrix, resulting in weaker imbibition of brine. Although the two cases showed different characteristics of the mass transfer through fracture/matrix interface, they resulted in similar values of final water saturation in the matrix. Hence, the surfactant injection was more efficient for a given amount of oil recovery when there was no initial water in the matrix.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.32)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Improving Recovery in the Yates Field Using Dynamic Feedback Loop based on Physics-Informed Artificial Intelligence
De Bruyker, Dirk (NeoTek Energy) | Kosut, Robert (SC Solutions) | Valdez, Raul | Haymes, Seth (Kinder Morgan) | Schoeling, Lanny | Petro, Miroslav | Weiner, Douglas | Joseph, Alfred (NeoTek Energy) | Lee, Jun Kyu | Emami-Naeini, Abbas | Ebert, Jon | Ghosal, Sarbajit (SC Solutions)
Abstract We present a robust control system and methodology for physics-informed artificial intelligence (PAI) used to optimize and improve oil recovery, demonstrated in the Yates Field operated by the Kinder Morgan CO2 company. The system consists of a robust control system (referred to as Dynamic Feedback Loop, or DFL) equipped with novel hydrocarbon sensors that measure oil concentration and other parameters continuously and simultaneously on a set of producing wells. The goal of this system is to optimize operational parameters (e.g. choke valve settings, injection rates) to reach specific target metrics of production (e.g. maximizing produced oil while minimizing produced gas). The key element of our approach is the use of a multi-layer artificial neural network (deep neural network, or DNN, to be specific) that extracts physics-based parameters from the real-time measurements and predicts relevant parameters of the DFL control system. DNNs are prone to overfitting in training, making them ineffective in unfamiliar or challenging situations outside the training dataset. To overcome this problem, we have developed a physics-informed robust neural network technique, where the reservoir physics and sensor data are used to train DNN representations of the key physical parameters. Typically, only simplified physical models are developed using available geostatic or historical production data. Also, due to the dynamic nature of these systems, the accuracy of the models often changes over time. To improve predictive capability of the model, we combine the DNN with the system-theoretic robust control concepts based on physics with a model uncertainty formulation. The concept was first validated using a combination of simulations, isolated sensor data and analyses based on sets of historic production data. A study using historic production data on Kinder Morgan's Yates Field Unit (YFU) 4045 Pilot (3 producing wells) indicates application of the DFL system results in an increase in cumulative production of up to 35% per year, compared to what is obtained through a traditional (fixed-point) control system. Currently, the DFL is being field-tested on a different set of wells in the Yates Field, instrumented with the novel hydrocarbon sensors that generate continuous and simultaneous production data.
- 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...)
CO2 Foam Field Pilot Design and Initial Results
Alcorn, Zachary Paul (University of Bergen) | Føyen, Tore (University of Bergen/SINTEF Industry) | Zhang, Leilei (Rice University) | Karakas, Metin (University of Bergen) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George (Rice University) | Graue, Arne (University of Bergen)
Abstract This paper presents the field design, monitoring program, and initial results from a CO2 foam pilot in East Seminole Field, Permian Basin, USA. Tertiary miscible CO2 injection has suffered from poor areal sweep efficiency due to reservoir heterogeneity and an unfavorable mobility ratio between CO2 and reservoir fluids. A surfactant-stabilized foam was selected to reduce CO2 mobility for increasing oil recovery and CO2 storage potential in an inverted 40-acre five spot well pattern. The foam system was designed to maximize the success of foam generation through surfactant screening and optimizing surfactant concentration and foam strength. Previous work identified a water-soluble, non-ionic surfactant at a concentration of 0.5 weight percent (wt%) and 70% foam quality for the pilot. A surfactant-alternating-gas (SAG) injection strategy, consisting of 10 days of surfactant solution injection followed by 20 days of CO2, began in May 2019. Baseline CO2 injection profiles, tracer tests, injection bottom hole pressures, and flow rates were collected for comparison to pilot surveys. The pilot monitoring program included repeat injection profiles, tracer tests, three-phase production monitoring, and collection of downhole pressure data for evaluation of reservoir response to foam injection. Produced fluids were also collected for chemical analysis to determine surfactant breakthrough time. A field injection unit was designed to meet the requirements of surfactant delivery, mixing, and storing. A methodology was also established to effectively validate foam formulation consistency in the field. Initial results revealed that pilot CO2 injectivity was reduced by 70%, compared to baseline CO2 injection, indicating reduced CO2 mobility after each surfactant slug. Baseline and pilot injection profiles show increased flow into the reservoir interval and potential blockage of a high permeability streak. The baseline CO2 tracer test measured CO2 breakthrough in 22 days, in one of the pattern producers. Expected breakthrough, based upon simulation, is 66 days during the pilot, which will be verified by a repeat tracer test at the end of the pilot. Production response is not expected for another six to nine months due to the volumes injected during the pilot. However, the early signs of sustained oil production despite less volume injected during the pilot indicate an initial positive response to foam.
- North America > United States > Texas (0.87)
- North America > United States > Oklahoma (0.67)
- Europe > United Kingdom > North Sea > Central North Sea (0.41)
- 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)
- (24 more...)
Planning for Large Scale ASP Flood Implementation in Mangala Oil Field
Pandey, Amitabh (Cairn Oil & Gas, Vedanta Limited) | Jain, Shakti (Cairn Oil & Gas, Vedanta Limited) | Prasad, Dhruva (Cairn Oil & Gas, Vedanta Limited) | Koduru, Nitish (Cairn Oil & Gas, Vedanta Limited) | Raj, Rahul (Cairn Oil & Gas, Vedanta Limited)
Abstract A highly successful ASP flood pilot has been conducted in the Mangala oil field in the Barmer basin located in the Rajasthan state of western India. The field which contains paraffinic oil with ~15cP oil viscosity is currently under full field polymer flood. The field has a STOIIP of ~1300 mmbbls and has already achieved more than 30% recovery factor in 10 years of production since coming online in 2009. The ongoing polymer flood is performing satisfactorily and the objective of large scale ASP implementation is to arrest the projected production decline and improve the ultimate recovery from the field. A normal 5-spot ASP pilot was conducted in the topmost reservoir of the field during the year 2014-15. The ASP formulation contained surfactant combination of high molecular weight TSP-EO-PO-sulfate and high carbon number ABS. The pilot was highly successful with estimated incremental recovery by ASP injection of more than 20% of the pilot STOIIP over polymer flood. The water-cut in the pilot dropped from more than 90% to levels of 20-30%. Comprehensive modeling of the corefloods and the pilot performance helped to calibrate the chemical flood simulator which was used for the development of large scale implementation concept. Various produced fluid related studies helped to design the surface facility concept. Given that large volumes of chemicals will be used, work is ongoing to define the chemical procurement strategy. The sector level modeling studies indicated that closer spacing improves the response time and helps to maximize the reserves in a given time frame. The study identified that infill drilling to convert the existing 5-spot polymer flood pattern into a direct line drive pattern is an optimal concept. The modeling study in combination with the surface facility considerations helped to design the expansion approach. The slug size sensitivity suggested to use slightly bigger pore volume of ASP slug in the range of 0.4-0.6 PV taking into consideration heterogeneity uncertainties attached with flooding multiple sands in fluvial deposition. The facility studies using the pilot information and additional lab studies helped to design the surface facilities concept. Requirement of produced water reinjection and water softening of the water for ASP injection in combination with anticipated scaling and produced fluid separation issues posed significant challenges. The paper will present the development journey of a very large scale ASP implementation concept in the Mangala field with focus on modeling at core/pilot/sector/full-field scale. The uncertainties associated with modeling of complex mechanism of the process will also be discussed. A high level surface facility concept and chemical procurement strategy will also be presented. This would be one of the few case history of a very large scale ASP implementation planning project.
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.34)
- Geology > Mineral > Sulfate (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
Abstract This paper discusses surfactant, co-solvent, alkali and polymer (ASP) formulations developed for the Kuparuk Field in Alaska. This field is a mature conventional reservoir that exhibits favorable characteristics for surfactant flooding. The formulations have been tested in the laboratory and in the field with good results. In core floods with live oil and reservoir core, oil saturation has been driven below 5% (Sorc) recovering more than 90% of the waterflood residual oil (Sorw). An ASP treatment, via a single well chemical tracer test, has yielded an Sorc of 1% recovering 96% of the Sorw in the field. However, the process of developing ASP formulations that effectively recover residual oil and represents a commercially viable ASP flood has been challenging. Driving the surfactant retention to low values has required the use of enhanced alkoxylated surfactants and co-solvents that provide low interfacial tension (IFT) micro-emulsions with low viscosity under broad salinity ranges. Kuparuk's rock mineralogy has also played an important role due its heterogeneity and high clay content. Clays with iron bearing minerals and significant ionic exchange have required a systematic study to better understand the effect of reservoir rock on the surfactant treatment. The impact of calcium and magnesium released by the reservoir rock was of primary concern. Significant results from the Kuparuk ASP formulation study are summarized. The performance of formulation components and their overall effect on surfactant retention, as well as rock mineralogy, are analyzed in detail. Experimental methodologies, analytical studies, and adequate core flood practices used to overcome challenges are also discussed. The lessons learned from this study have the potential to be used in other Alaskan fields, unlocking vast and valuable resources from mature reservoirs as well as new discoveries.
- Geology > Mineral > Silicate (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Geological Subdiscipline > Mineralogy (0.45)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Illinois > Loudon Field (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field > Kuparuk Formation (0.96)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.89)
X-Ray CT Investigation of Displacement Mechanisms for Heavy Oil Recovery by Low Concentration HPAM Polymers
Skauge, Arne (University of Bergen) | Shaker Shiran, Behruz (NORCE Energy) | Ormehaug, Per Arne (NORCE Energy) | Santanach Carreras, Enric (TOTAL E&P) | Klimenko, Alexandra (TOTAL E&P) | Levitt, David (TOTAL E&P)
Abstract Polymer flooding has proved to be a successful EOR method in very heavy oil reservoirs, despite failure to achieve a favorable mobility ratio even with polymer, which was originally imagined to be a necessary criterion for success based upon fractional flow theory. In a previous study (Levitt et al. 2013), we demonstrated a surprisingly high oil recovery with low concentration (and viscosity) partially hydrolyzed polyacrylamide (HPAM) polymer solutions of only 3 cP displacing a 2000 cP oil. Additional experiments with more viscous as well as non-elastic viscosifying agents demonstrated that recovery is not sensitive to viscosity, and thus cannot be understood through fractional flow theory. The scope of this paper is to understand where additional recovery comes from through visualization using CT imaging, in order to allow operative driving mechanisms to be optimized. Two long core (30 cm) flooding experiments have been performed to understand oil recovery at adverse mobility ratio. The first experiment started with waterflooding followed with polymer flooding (3 cP), while the second experiment started with polymer flooding directly. In-situ saturations were obtained by a medical CT scanner operated at high energy level, and used two X-ray sources and two array detectors simultaneously. The procedure was to perform the waterflood or polymer flood direct in the CT scanner. That will give us the finger development from early stage until a well-established channel is developed. The frontal velocity was about 1 ft/day. The displacements were further analyzed through simulations and dynamic pore scale model to understand the changes in fluid flow. CT imaging demonstrated that increased oil recovery with low-concentration HPAM solutions is correlated with an increase in finger width, rather than for instance an increase in finger density. This is in agreement with observed behavior of unstable displacements involving viscoelastic fluids in Hele-Shaw cells (Bonn et al., 1995). These results suggest that elasticity may be more significant than viscosity in optimizing oil recovery under highly unstable conditions, for example with oils of ~1000 cP or higher. Presence of fingering under both water and polymer flood was also confirmed, with dominant finger diameter on the order of 1 mm (under waterflood) to 2 mm (under polymer flood). Fingers grow in thickness and length, and near the inlet they start quickly to overlap. Fingers are formed mostly in the middle of the core and fewer fingers appear near the wall of the core. CT shows that the waterflood is dominated by viscous fingering. Experimental CT data together with simulations and pore scale modelling have demonstrated that increased oil recovery with low-concentration HPAM solutions is correlated with an increase in finger width, rather than for instance an increase in finger density or stabilization of the displacement front. Among other things, these results demonstrate that the assumption of capillary equilibrium is inappropriate under these conditions, and thus that fractional flow theory is poorly suited to predicting or optimizing recovery.
- Europe (1.00)
- Asia (0.94)
- North America > United States > Oklahoma (0.28)
- (2 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
Numerical Simulation of Crossed-Linked Polymer Injection in Dina Cretaceous Field: A Real Field Case Study
Izadi, Mehdi (Ecopetrol SA) | Jimenez, Jaime Alberto (Ecopetrol SA) | Zapata, Jose Francisco (Ecopetrol SA) | Felipe Castillo, Andres (Ecopetrol) | Pinto, John (Ecopetrol SA) | Vicente, Sebastian (Ecopetrol SA)
Abstract The main objective of this work is to shed light on the mechanism of modeling crossed-linked polymer (CLP) technology, by incorporating real field pilot injection and production data in the Dina Cretaceous field located in the Upper Magdalena Valley (UMV) Basin in Colombia. The paper will highlight why original simulation model predictions differ from the actual observed field data and the predictability of numerical simulation of CEOR process would be discussed and presented. Despite successful application and positive field results in the literature, the propagation of CLP system in porous media has been challenged with conflicting opinions and reports and still remains debatable and uncertain. This paper will use recent experimental laboratory data in conjunction with actual field data to properly explain the possible mechanism of CLP and offer practical modeling techniques to capture experimental and field data. Therefore a modeling methodology was developed and used to model the field data, this method is based on previous modeling mechanisms with incorporating a new grid-based residual resistance factor (RRF) and pore throat sizes. The model requires a proper understanding of rock typing and populate the permeability distribution based on pore throat sizes. The new modeling mechanism was able to reasonably predict the pilot performance in some of the offset producers. To model delayed viscosification and adsorption of the CLP process, two approaches has been evaluated and used in the original simulation model, the use of multiple regions and chemical reaction. The chemical reaction rate is tuned to calibrate laboratory data and to model the delayed viscosification and RRF. However recent laboratory experiments explained the possible mechanisms of CLP formation through intra-molecular crosslinking and intra-inter-molecular crosslinking. In conclusion, because of extensive and numerous laboratory experiments and the conduct of field pilot results, proposed numerical modeling demonstrate the complexity of modeling the CLP system and offers a practical solution to the field applications.
- South America > Colombia (0.68)
- Europe > United Kingdom > North Sea > Central North Sea (0.45)
- North America > United States > Oklahoma (0.29)
- South America > Colombia > Huila Department > Dina Field (0.99)
- North America > United States > Oklahoma > Anadarko Basin > North Burbank Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- (2 more...)
CO2 Foam Pilot in a West Texas Field: Design, Operation and Results
Mirzaei, Mohammad (Occidental Oil and Gas) | Kumar, Deepanshu (Occidental Oil and Gas) | Turner, Dwight (Occidental Oil and Gas) | Shock, Austin (Occidental Oil and Gas) | Andel, Derek (Occidental Oil and Gas) | Hampton, David (Occidental Oil and Gas) | Knight, Troy E. (Dow) | Katiyar, Amit (Dow) | Patil, Pramod D. (Dow) | Rozowski, Peter (Dow) | Nguyen, Quoc P. (The Univesity of Texas at Austin)
Abstract In this paper, we describe the design, implementation and results of a CO2 foam pilot in a mature CO2 flood in West Texas. The objective of the pilot was to demonstrate improved conformance/sweep efficiency of the CO2 foam over CO2 WAG injection. Laboratory experiments to guide design of the flood and the monitoring program to understand and model flood performance are described. Monitoring included rate and pressure tracking, injection profiles and inter-well tracer programs before and during the foam flood. While changes in injection rate and injection profile confirmed the formation of strong foam near the wellbore and redistribution of fluids in the injectors, oil response was weak, with significant oil gain observed in one of the four patterns. The gas production rate also changed very slightly from the baseline conditions. The comprehensive monitoring program in this pilot provides new insights into effectiveness of CO2 foam in actual field applications. The results from this pilot may help to better screen and design future foam injection pilots.
- North America > United States > Texas > Permian Basin > Salt Creek Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- (10 more...)
Economic Assessment of Strategies for CO2-EOR and Storage in Brownfield Residual Oil Zones: A Case Study from the Seminole San Andres Unit
Ren, Bo (The University of Texas at Austin) | Duncan, Ian (The University of Texas at Austin) | Male, Frank (The University of Texas at Austin) | Baqués, Vinyet (The University of Texas at Austin) | Lake, Larry (The University of Texas at Austin)
Abstract Brownfield residual oil zones (ROZ) may benefit from specific strategies to maximize production. We evaluated several strategies for producing from the Seminole ROZ. This ROZ lies below the main pay zone (MPZ) of the field. Such brownfield ROZs occur in the Permian Basin and elsewhere, formed by the action of regional aquifers over geologic time. CO2 can be injected into these zones to enhance oil recovery and carbon storage. Since brownfield ROZs are hydraulically connected to the MPZs, development sequences and schemes should influence oil production, CO2 storage, and net present value (NPV). We conducted economic assessments of various CO2 injection/production schemes in the Seminole stacked ROZ-MPZ reservoir based on flow simulations. First, we constructed a high-resolution geocellular model from a seismic survey, wireline logs and core data. To calibrate the geological model and constrain the interface between the ROZ and the MPZ, we performed a comprehensive production-pressure history matching of primary depletion and secondary waterflooding. After this, we conducted flow simulations of water alternating gas (WAG) injection into the reservoir while considering several injection/productions schemes (e.g., switching injection from the MPZ to the ROZ, commingled production). For each scheme, various WAG ratios (i.e., reservoir volume ratio between injected water and CO2) were tested to find the maximum oil production and maximum CO2 storage. We assessed the economic results for each WAG ratio case on NPV. The results from simulating various injection/production schemes showed that simultaneous CO2 injection into the MPZ and ROZ favors oil production. If instead, CO2 is injected into the MPZ and ROZ, then into the ROZ alone, this leads to increased CO2 storage. Storage performance is influenced by the interplay between the crossflow from the MPZ to ROZ and WAG ratios. As the WAG ratio increases, the amount of CO2 stored decreases more for commingled injection cases than for separated ROZ injection cases. Also, the WAG ratio leading to maximum oil production does not necessarily yield the largest NPV, because of the complicated interactions among CO2 consumption, reservoir heterogeneity, and oil recovery. Brownfield ROZs are common below San Andres reservoirs in the Permian Basin, and they can be exploited to increase oilfields’ NPV and carbon storage potential. Our case study on the Seminole MPZ-ROZ is an analog for other similar reservoirs. We demonstrate that development sequences and WAG ratios influence the performance of CO2 EOR and storage. Thus, this work provides valuable insights into the further optimization of brownfield ROZ development and helps operators to plan flexible storage goals for stacked ROZ-MPZ reservoirs.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.69)
- Geology > Geological Subdiscipline (0.68)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- 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)
- (28 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)