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The projects are designed to reduce technical risks in enhanced oil recovery and expand application of EOR methods in conventional and unconventional reservoirs. This paper presents an overview of the SACROC Unit’s activity focusing on different carbon dioxide (CO2) injection and water-alternating-gas (WAG) projects that have made the SACROC unit one of the most successful CO2 injection projects in the world. A new type of organically modified silica glass that can remove a wide variety of oils and contaminants from produced and flowback water is showing promising results as it undergoes field trials.
This paper presents an analysis of a CO2-foam-injection pilot in the Salt Creek Field, Natrona County, Wyoming. A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Aqueous foam has been demonstrated to have promise in conformance-control applications. This paper explores the foaming behavior of a CO2-soluble, cationic, amine-based surfactant. A growing chorus of suppliers, researchers, and service companies is persuading US operators to re-examine their use of slickwater in shale plays and consider displacing it with carbon dioxide and nitrogen.
Although polymer flooding has become a promising enhanced oil recovery (EOR) technique, no field tests have been performed to date in Alaska’s underdeveloped heavy-oil reservoirs. The green light comes 4 years after the privately-held firm filed its development and production plan. Liberty Island would consist of gravel, stretch 9 acres, and sit just a few miles offshore. Well fires look all consuming, but proving they burn all the oil without leaving a spill behind required the efforts of Boots Coots plus a rocket scientist and a lot of high powered computer equipment. Major oil discoveries by Armstrong Oil & Gas and ConocoPhillips have compelled the US Department of the Interior to reassess its estimate of undiscovered, technically recoverable resources in parts of Alaska.
Although polymer flooding has become a promising enhanced oil recovery (EOR) technique, no field tests have been performed to date in Alaska’s underdeveloped heavy-oil reservoirs. Initially, polymer flooding had not been considered as a viable enhanced-oil-recover (EOR) technology for Pelican Lake in northern Alberta, Canada, because of the high viscosity of the oil until it was considered in combination with horizontal wells.
GlassPoint Solar was founded in 2008 to replace the use of natural gas for steamflooding heavy-oil reservoirs. But amid low energy prices, its chief investor has decided to pull the plug for good. The projects are designed to reduce technical risks in enhanced oil recovery and expand application of EOR methods in conventional and unconventional reservoirs. There is every reason to believe that enhanced oil recovery through huff-and-puff injections in US tight-oil plays could be a technical success across large numbers of wells. However, widespread economic success remains uncertain.
The complete paper discusses the importance of adequate preparation and the approaches used to overcome challenges of EOR operations, including handling back-produced polymer. The complete paper presents steps to accelerate enhanced oil recovery (EOR) in a Grimbeek field from a four-injector pilot to 80 new injectors in a rapid deployment. Duri Field in Indonesia is the largest active steamflood project in the world. The field produces 73,000 BOPD, and 10,000 optimization jobs are executed annually to support base production. Autonomous Inflow Control Valve technology demonstrates significant benefits within first year.
Write-offs include billions for early-exploration-stage projects that the company will now cut. Phase 1 is expected to be operational in 2024. BP says it is firmly committed to achieving the ambitious target of net-zero greenhouse gas emissions over the next 30 years—even if that means producing less oil and gas. The industry is becoming increasingly complex, leading to changes in how universities approach education for undergraduate study. The report card for unconventional oil and gas producers from a leading industry analyst is A+ for growth and F- for paying back investors.
This popular course is based on the SPE Monograph Volume 22, Practical Aspects of CO2 Flooding, and is an outgrowth of The University of Texas of the Permian Basin and the SPE CO2 conferences, and training courses held in Midland, Texas over the past 13 years. The instructors spend most of the time on the practical aspects of CO2 flooding, keeping the theoretical aspects to a bare minimum. Instructors also discuss the economics of CO2 flooding compared to waterflooding. If there is enough interest among the participants, there will also be a discussion of CO2 geosequestration. Each attendee will receive a workbook containing copies of the instructors’ PowerPoint presentations, and solutions to the problems given in class.
With the current trend for application of Enhanced Oil Recovery (EOR) technologies, there has been much research into the possible upsets to production, from the nature of the produced fluids to changes in the scaling regime. One key question that is yet to be addressed is the influence of EOR chemicals, such as hydrolysed polyacrylamide (HPAM), on scale inhibitor (SI) squeeze lifetime. Squeeze lifetime is defined by the adsorption of the inhibitor onto the reservoir rock, hence any chemical that interacts with the adsorption process will have an impact on the squeeze lifetime. This paper experimentally demonstrates potential changes to inhibitor adsorption from a polymer EOR project by demonstrating the complex interactions between HPAM and phosphonate scale inhibitors with respect to adsorption.
This work presents a detailed coreflooding programme, supplemented with bottle tests, to identify the impact of HPAM on a diethylenetriamine penta(methylene phosphonic acid) (DETPMP) squeeze lifetime. A range of pH values, representing the expected inhibitor injection pH, have been studied on consolidated and crushed Bentheimer sandstone. A temperature of 70°C is used throughout as it represents the likely maximum temperature at which HPAM would be applied and the typical temperature at which DETPMP would be used in squeeze applications.
The results presented show that scale inhibitor application pH is key in defining the impact of HPAM on DETPMP adsorption. Neutral pH displays a reduced squeeze lifetime, believed to be due to reduction of adsorption sites by HPAM. However, this impact could be countered by injecting this type of scale inhibitor at a low pH (e.g. pH 2). Static tests performed alongside the corefloods show that even low inhibitor concentrations (as found in SI pre-flushes) are sufficiently acidic to fully precipitate the HPAM from solution, but did not impact the adsorption.
This study suggests, contrary to the commonly held view in the industry that EOR polymers may negatively impact squeeze lifetime, that with the correct selection of inhibitor type and their application pH it is possible to achieve the same results as in a conventional reservoir.
Al Kalbani, Munther Mohammed (Heriot-Watt University) | Jordan, Myles Martin (Champion X) | Mackay, Eric James (Heriot-Watt University) | Sorbie, Ken Stuart (Heriot-Watt University) | Nghiem, Long X. (Computer Modelling Group Ltd.)
Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the
Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options.
Results show that the
This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.