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Collaborating Authors
Permian Basin
Abstract Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO2, whether in aquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstrated for foam that would assist CO2 sequestration, in particular sweep efficiency and residual trapping, and the challenges yet to be overcome. CO2 is trapped in porous geological layers by an impermeable overburden layer and residual trapping, dissolution into resident brine, and conversion to minerals in the pore space. Over-filling of geological traps and gravity segregation of injected CO2 can lead to excessive stress and cracking of the overburden. Maximizing storage while minimizing overburden stress in the near term depends on residual trapping in the swept zone. Therefore, we review the research and field-trial literature on CO2 foam sweep efficiency and capillary gas trapping in foam. We also review issues involved in surfactant selection for CO2 foam applications. Foam increases both sweep efficiency and residual gas saturation in the region swept. Both properties reduce gravity segregation of CO2. Among gases injected in EOR, CO2 has advantages of easier foam generation, better injectivity, and better prospects for long-distance foam propagation at low pressure gradient. In CO2 injection into aquifers, there is not the issue of destabilization of foam by contact with oil, as in EOR. In all reservoirs, surfactant-alternating-gas foam injection maximizes sweep efficiency while reducing injection pressure compared to direct foam injection. In heterogeneous formations, foam helps equalize injection over various layers. In addition, spontaneous foam generation at layer boundaries reduces gravity segregation of CO2. Challenges to foam-assisted CO2 sequestration include the following: 1) verifying the advantages indicated by laboratory research at the field scale 2) optimizing surfactant performance, while further reducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution of surfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactant degrades or is diluted. 4) verifying whether foam can block upward flow of CO2 through overburden, either through pore pathways or microfractures. 5) optimizing injectivity and sweep efficiency in the field-design strategy. We review foam field trials for EOR and the state of the art from laboratory and modeling research on CO2 foam properties to present the prospects and challenges for foam-assisted CO2 sequestration.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Oklahoma (0.68)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (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)
- (43 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (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 A CO2 foam pilot was conducted in a heterogeneous carbonate reservoir in East Seminole Field, Permian Basin USA. The primary objective was to achieve in-depth CO2 mobility control to increase CO2 sweep efficiency and improve oil recovery in an inverted 40 acre 5-spot pattern. Foam was injected in a rapid surfactant-alternating-gas (SAG) strategy with 10 days of surfactant solution injection followed by 20 days of CO2 injection. We implemented a laboratory to field upscaling approach which included foam formulation screening, numerical modeling, and field monitoring to verify foam generation and CO2 mobility reduction. The monitoring campaign obtained baseline before the pilot and monitored reservoir response to foam injection. This included conducting baseline and pilot phase CO2 and water injection profile logs, interwell CO2 tracer tests and collecting injection bottom hole pressure data and flow rates. Transient analysis was also conducted to assess foam development at reservoir conditions. The effectiveness of foam in improving overall recovery was also evaluated. Results indicate that foam was generated and CO2 mobility was reduced during the pilot based upon higher differential pressures during the SAG cycles compared to an identical water-alternating-gas (WAG) cycle. CO2 breakthrough was also delayed with foam compared to the baseline test without foam. Injection profile logs from the foam injector showed that flow increased into unswept reservoir intervals and was diverted from a high permeability streak. The effectiveness of foam in improving the overall oil recovery revealed that the foam pilot produced 30% more oil than the pattern's projected performance without foam, despite injecting at half of the historical rate during the pilot. This work presents the complete field results and analysis from the successful implementation of CO2 foam mobility control.
- 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...)
Use of Horizontal Injectors for Improving Injectivity and Conformance in Polymer Floods
Hwang, Jongsoo (The University of Texas Austin) | Zheng, Shuang (The University of Texas Austin) | Sharma, Mukul (The University of Texas Austin) | Chiotoroiu, Maria-Magdalena (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH)
Abstract Several field cases have demonstrated polymer injection in a horizontal well increases oil recovery. It is important to maintain high injectivity while preventing injection-induced fractures to ensure good reservoir sweep. Our primary goal in this paper is to better understand polymer injection data from horizontal injectors in the Matzen field using a fully integrated reservoir, geomechanics, and fracturing model. By simulating polymer injection history, we present several advantages of horizontal injectors over the vertical wells. Horizontal injectors delay fracture initiation and provide better tolerance to polymer plugging on the wellbore surface. Simulations explain the measured PLT data of fluid distributions influenced by accumulated polymer deposition in multiple zones. We show that gradual injectivity decline is attributed to both polymer filter cake buildup and high-viscosity, shear-thickening zones created around the wellbore. The field case simulation also clarifies the flow distribution in different sands and how polymer rheology affects this. This distribution is found to be different than for water injection. Results from periodic acid treatments clearly show that free-flowing particles in the polymer solution are responsible for formation damage. Polymer plugging and the viscous pressure drop in the shear-thickening zone are the primary factor affecting the measured injection pressure. Based on the strong near-wellbore viscosity impact, geomechanical simulations identify reservoir zones prone to fracture growth during long-term injection, and we suggest strategies to avoid injection induced fractures that can lead to poor conformance.
- Europe (1.00)
- North America > United States > Alaska (0.28)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.51)
- 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)
- (37 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...)
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)
An Integrated CO2 Foam EOR Pilot Program with Combined CCUS in an Onshore Texas Heterogeneous Carbonate Field
Alcorn, Z. P. (Department of Physics and Technology, University of Bergen) | Fredriksen, S. B. (Department of Physics and Technology, University of Bergen) | Sharma, M.. (The National IOR Centre of Norway, University of Stavanger) | Rognmo, A. U. (Department of Physics and Technology, University of Bergen) | Føyen, T. L. (Department of Physics and Technology, University of Bergen) | Fernø, M. A. (Department of Physics and Technology, University of Bergen) | Graue, A.. (Department of Physics and Technology, University of Bergen)
Abstract A CO2 foam enhanced oil recovery (EOR) field pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results due to injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a more integrated multiscale methodology is required for project design to further understand the connection between laboratory and field scale displacement mechanisms. Foam is frequently generated in a reservoir through the injection of alternating slugs of surfactant solution and gas (SAG). To reduce costs and increase the success of in-situ foam generation, SAG operations must be optimized for field implementation. This study presents an integrated upscaling approach for designing a CO2 foam field trial, including pilot well selection criteria, comprehensive laboratory coreflood experiments combined with reservoir scale simulation to offer recommendations for a SAG injection schedule while assessing CO2 storage potential. Laboratory investigations include dynamic aging, foam stability scans, CO2 foam EOR corefloods with associated CO2 storage, and unsteady state CO2/water endpoint relative permeability measurements. Wettability tests of restored reservoir core material yield Amott-Harvey index values of −0.04 and −0.79, indicating weakly oil wet to oil wet conditions. Foam scans demonstrate highest foam quality at gas fraction (fg) of 0.70. CO2 foam EOR corefloods after completed waterfloods, at optimal foam quality, result in a total recovery factor of 80% OOIP with an incremental recovery of 35% OOIP by CO2 foam. A negligible difference is observed in incremental CO2 foam recoveries and apparent viscosities when using 1 wt% and 0.5wt% surfactant solution. High differential pressures during CO2 foam suggest generation of stable foam with mobility reduction factors by CO2 foam up to 340, over CO2 at reservoir conditions. CO2 storage potential was assessed during displacement to investigate the carbon footprint of CO2 foam injection. Relative permeability endpoints and foam stability scan parameters are input into a validated field scale numerical simulation model to recommend design parameters for SAG injection. The numerical model investigates foam's impacts on oil recovery, gas mobility reduction, producing gas oil ratio (GOR), and CO2 utilization. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.
- North America > United States > Texas (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.25)
- Geology > Rock Type > Sedimentary Rock (0.68)
- Geology > Sedimentary Geology > Depositional Environment (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)
- (25 more...)
CO2 Foam Pilot in Salt Creek Field, Natrona County, WY: Phase III: Analysis of Pilot Performance
Mukherjee, Joydeep (The Dow Chemical Company) | Nguyen, Quoc P. (The University of Texas at Austin) | Scherlin, John (Fleurde Lis Energy) | Vanderwal, Paul (The Dow Chemical Company) | Rozowski, Peter (The Dow Chemical Company)
Abstract A supercritical CO2 foam pilot, comprised of a central injection well in an inverted 5-spot pattern, was implemented in September 2013 in Salt Creek field, Natrona County WY. In this paper we present a thorough analysis of the pilot performance data that has been collected to date from the field. A monitoring plan was developed to analyze the performance of the pilot area wells before and after the start of the foam pilot. The injection well tubing head pressure was controlled to maintain a constant bottom hole pressure and the fluid injection rates were monitored to capture the effect of foam generation on injectivity. Inter-well tracer studies were performed to analyze the change in CO2 flow patterns in the reservoir. Production response was monitored by performing frequent well tests. The CO2 injection rate profile monitored over several WAG cycles during the course of the implementation clearly indicates the formation and propagation of foam deep into the reservoir. CO2 soluble tracer studies performed before and after the start of the foam pilot indicate significant areal diversion of CO2. The production characteristics of the four producing wells in the pilot area indicate significant mobilization of reservoir fluids attributable to CO2 diversion in the pattern. The produced gas-liquid ratio has decreased in all four of the producing wells in the pattern. Analysis of the oil production rates shows a favorable slope change with respect to pore volumes of CO2 injected. Segregation of CO2 and water close to the injection well seems to be the primary factor adversely affecting CO2 sweep efficiency in the pilot area. Foam generation leads to a gradual expansion of the gas override zone. The gradual expansion of the gas override zone seems to be the principal mechanism behind the production responses observed from the pilot area wells.
- North America > United States > Wyoming > Johnson County (0.61)
- North America > United States > Texas > Kent County (0.61)
- North America > United States > Wyoming > Natrona County (0.61)
- North America > United States > West Virginia > Rock Creek Field (0.99)
- North America > United States > Texas > Permian Basin > Salt Creek Field (0.99)
- North America > United States > Kansas > Estes Field (0.99)
- (12 more...)
Field Test Results of a New Silicate Gel System that is Effective in Carbon Dioxide Enhanced Recovery and Waterfloods
Oglesby, Kenneth D. (Impact Technologies LLC) | D'Souza, David (Denbury Resources) | Roller, Chad (MidCon-Energy Partners LP) | Logsdon, Ryan (MidCon-Energy Partners LP) | Burns, Lyle D. (Clean Tech Innovations, LLC) | Felber, Betty J. (EOR Consultant)
Abstract Field test results of a new silicate based Silicate-Polymer-Initiator (SPI) gel system for zonal conformance control are presented from: 3 treatments in a central Mississippi sandstone carbon dioxide (CO2) flood, including 1 producer; 5 injector treatments in a mature, west Texas San Andres dolomite, CO2 flood under Water-Alternating-Gas (WAG) operation; and 2 injector treatments in a northeast Oklahoma waterflood. Gel treatment volumes ranged from 130 to 4,349 barrels of the patented, environmentally friendly, silicate gel system that is pumped at a near water viscosity and density. That pre-gel liquid is triggered to a gel by a pH change caused by external or internal initiation methods. One unique aspect of these silicate solutions is that they can be initiated by both the pre- and post-treatment injected CO2 itself. Alternately, other external and internal initiators can be used in both CO2 and water-floods. Targeted gel times ranged from 1 hour up to 6 days, with maximum gel strength generated within 2–4 weeks. The resultant silicate gels are 10 times stronger than any known gelled polymer system, per CTI laboratory Extrusion and Penetrometer testing. Selected additives were utilized in the gel treatment fluids to focus the pre-gelled solutions into the desired high permeability zones. Furthermore, pre-gel fluid entry into water or oil zones will not set the silicate gel, but will instead dilute the leading edge. Rate, pressure, injectivity and downhole profile surveys were used to evaluate the treatment in injection wells. Oil, water and gas rates, Water: Oil Ratios, Gas: Oil Ratios and CO2 utilization efficiency were used to evaluate treatments in production wells. Offset production wells were monitored, where possible, for production changes, sometimes seen outside the prior established patterns. Where the data was available, the new silicate gel field treatments were directly compared to prior polyacrylamide and similar conformance systems. In most cases, the new silicate system exhibited positive responses while previous polymer based systems did not respond.
- North America > United States > Oklahoma (1.00)
- North America > United States > Texas > Hockley County (0.28)
- Geology > Mineral > Silicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
- North America > United States > Texas > Permian Basin > Midland Basin > Slaughter Field (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Cleveland Field (0.99)
- North America > Mexico > Veracruz > Tampico-Misantla Basin > San Andres Field (0.99)
- (4 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Comprehensive Review of Fracture Control for Conformance Improvement in the Kuparuk River Unit - Alaska
Mishra, Ashok (Conoco Phillips) | Abbas, Sayeed (Conoco Phillips) | Braden, John (Conoco Phillips) | Hazen, Mike (Conoco Phillips) | Li, Gaoming (Conoco Phillips) | Peirce, John (Conoco Phillips) | Smith, David D. (Conoco Phillips) | Lantz, Michael (TIORCO, a Nalco Champion Company)
Abstract This paper is a field case review of the process and methodologies used to identify, characterize, design, and execute a solution for a waterflood conformance problem in the Kuparuk River Unit in late 2013. In addition, post treatment analysis in a complex WAG flood will be discussed. The Kuparuk River Field is a highly fractured and faulted, multi-layer sandstone reservoir located on the North Slope of Alaska. Large scale water injection in the field was initiated in 1981 and overall the field responded favorably to waterflood operations. In 1996, Kuparuk implemented a miscible WAG flood in many areas of the field. However, natural fault and fracture connectivity has resulted in some significant conformance issues between high angle wells in the periphery. Methodologies employed to identify and characterize one specific conformance issue will be outlined. Details of diagnostic efforts, and how they were used to identify, characterize and mitigate an injector/producer interaction through a void space conduit will be discussed. The solution selected to resolve this conformance issue involved pumping a large crosslinked hydrolyzed polyacrylamide (HPAM) gel system. The solution used a tapered concentration design with one of the highest molecular weight HPAM polymers available. Before execution of this solution, extensive history matching and modeling of the solution design and benefits were used to justify this effort. These modeling efforts and their projections will be reviewed. This solution was pumped into the offending injector in late 2013, and offset producers were carefully monitored for gel breakthrough. The polymer treatment design parameters, including rates and pressure limits were used to generate an effective solution. A discussion of this active design approach, a complete review of the well problem dynamics, treatment operations, products used, and potential complications associated with these products will be discussed. Post solution execution performance analysis was difficult due to the active nature of this MWAG flood. A variety of plotting and analysis techniques were used to identify and quantify the results. A discussion of these results will be provided. Finally, a summary of lessons learned, and a limited discussion of future plans will be presented.
- North America > United States > Alaska > North Slope Borough (1.00)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- Geology > Structural Geology > Fault (0.66)
- North America > United States > Wyoming > Wertz Field (0.99)
- North America > United States > Texas > Permian Basin > SACROC Unit > Lower Clear Fork Formation (0.99)
- North America > United States > Texas > Permian Basin > SACROC Unit > Cisco Sand Formation (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)