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Abstract The design of an offshore chemical EOR project involves not just reservoir engineering, logistics and chemical storage issues. Oil/water separation, produced water treatment, incompatibilities with other chemicals, precipitation on surface facilities and high salinity and hardness water source are among the items that must be evaluated. For polymer flooding, as the main offshore injection water source is seawater or produced water, the salinity and hardness will decrease the viscosifying power of conventional Partially Hydrolyzed Polyacrylamides (PHPA). For small pilots, the chemical consumption of PHPA allows the polymer storage and preparation plant to be whole built on the FPSO deck. Full-field applications may consider independent units for chemical storage and preparation. Proposed full-field alternatives for reducing the polymer consumption are polymers with higher salinity tolerance or reducing the injection water salinity and hardness. Technical and economic analyses are required to compare the alternatives. Another concern on offshore polymer flooding is the large well spacing, requiring polymers with extended thermal resistance in hard water. At elevated temperatures, even modified polyacrylamides cannot resist long enough. It's also recommended to avoid high shear rate regions during the injection, reducing the need of polymer overdosage to compensate the viscosity loss due to mechanical degradation. The ASP/SP method has a considerable higher chemical consumption than polymer flooding. Moreover, regular alkalis cannot be used in hard water, requiring hardness insensitive alkalis or water softening. Water desalinization will be necessary to ensure that the salinity gradient required for the ASP/SP method can be attained. Like for polymer flooding, the application of the ASP/SP method may consider an independent unit for chemical storage and water desalinization/softening. Oil/water separation and produced water treatment must be designed in order to be able to treat the back produced fluids containing the EOR chemicals. Chemical EOR methods are an important strategy to increase the recovery factor of offshore fields, especially where there is no gas available for EOR and thermal methods are not suitable. Important steps are being taken on logistics, chemical and process developments in order to overcome the challenges on making chemical EOR deepwater offshore technically and economically viable.
Abstract The growing popularity of water-based Enhanced Oil Recovery (EOR) techniques, such as Low Salinity Injection (LSI), Chemical EOR (CEOR), and steam-flooding, impacts the water footprint of the oil and gas industry. It also affects the water treatment industry by creating new opportunities as a function of the requirements of equipment and systems in EOR projects. In some cases, the needed technologies have little to no history of application in the upstream oil and gas industry, therefore impacting EOR project budgets and schedules. These issues become particularly acute in offshore applications that are generally limited by footprint and weight, thereby further reducing suitable water treatment options. The issues are further confounded by the lack of communication between oil companies on equipment successes and failures in these new applications. EOR projects are often kept as low profile, particularly by smaller oil companies, to strengthen competitive advantages in the marketplace. One of the best treatment options for the environment is the reuse of produced water for re-injection in EOR applications. This is particularly attractive in CEOR where residual polymer and surfactant may deem the produced water unacceptable for discharge. But injection additives may stabilize emulsions and render the produced water and oil mixture challenging to separate. Ideally, water treatment technologies are used that both enable good separation and maximize potential reuse of produced water. As a first step in disseminating the current body of knowledge of water usage and treatment in EOR applications, a survey was conducted in 2012 of water-based EOR projects to ascertain their water source and background information on the water treatment technologies employed. The survey was co-sponsored by the Produced Water Society. Specific information on the source water salinity and temperature was obtained, in addition to the type of EOR used, the project location, and details of the existing treatment system(s). The survey results were then augmented with exhaustive literature searches of both full-scale EOR applications and emerging technology solutions currently being piloted. This paper describes the survey results which detail water-based data from more than fifty EOR projects around the world, along with a critique of the emerging technologies being piloted in global EOR field sites.
Abstract Daqing sandstone is the largest producing field in China, operated by CNPC's Daqing Oilfield Company. Despite more than 50 years of development, annual crude production currently is almost 40 mln tons of oil that is about 80% of plateau level. This successful long-term development is made possible through EOR programs. Chemical EOR is deployed in Daqing field from 1992 and currently accounts for ~14 mln tons of oil production annually, mainly by polymer flooding, world-largest in scale. Conventional hydrolyzed polyacrylamide (HPAM) copolymers were used in Daqing projects with fresh water for preparation of injection solution since the beginning. Today, mainly produced water is used for polymer preparation to improve field environmental and commercial performance. The salinity of produced water is moderate, of about ~5,100 mg/l. However, it contains crude oil, suspended solids, bacteria, iron, sulfide, residual polymer and other chemicals. Altogether they have large influence on polymer viscosity: for medium- and high-molecular-weight copolymers it can be reduced by 40-50% when switching from fresh to Daqing produced water. Then higher polymer concentration is required to achieve target viscosity. Operating Daqing Oilfield company, its institute, and polymer suppliers have conducted thorough experimental polymer screening with the following criteria: salinity resistance; providing target viscosity range at smaller concentrations (compared to regular HPAM); if feasible, better sweep efficiency – to increase oil recovery. Viscosity build-up, its retention, thermal stability, salinity tolerance, adsorption and oil displacement were compared. Terpolymer LH2500 was selected for field trial for produced water injection. It is manufactured by introducing 2-Acrylamido-2-methylpropane sulfonic acid (AMPS) group and micro-block template to HPAM molecule that improves the polymer linearity and resistance to salts and temperature. In different zones of Pu I2-3 layer two types of polymers were injected – conventional HPAM in fresh water and LH2500 polymer in produced water. In both areas watercut prior to polymer injection was similar – 95.9 and 95.5%, respectively; reservoir and fluids properties are very similar. LH2500 was injected in five-spot patterns with ~140 m well spacing. There are 33 injection wells and 37 producers in this area. LH2500 has demonstrated good injectivity, better sweep efficiency and in-situ viscosity stability and, therefore, recommended for use in the project expansion. Watercut reduction achieved is 16.6%, higher than for conventional HPAM with fresh water injection. Increase of oil production was observed in all 37 producers. The incremental recovery by LH2500 is greater at the same injection volume, which overperforms HPAM by adding 3.3% of oil-in-place to production on the date of analysis at similar injection volume. Also, this result is achieved with 35% less polymer that improves economics of polymer flooding in Daqing even further. The results correlate well with previous experimental findings. Incremental recovery in patterns swept by LH2500 continues to grow and forecasted to achieve over 18% (Zhou et al. 2015). This paper presents detailed description of AMPS terpolymer, polymer selection, experimental evaluation, field performance of LH2500 terpolymer, and incremental oil recovery analysis.
Raney, Kirk H. (Shell Exploration & Production) | Ayirala, Subhash C. (Shell International Exploration and Production Inc. ) | Chin, Robert W. (Shell International Exploration and Production Inc. ) | Verbeek, Paul (Shell International Exploration and Production Inc. )
Abstract Chemical enhanced oil recovery (EOR), including polymer and surfactant-based processes, is a method that operators consider to maximize oil recovery from onshore and offshore reservoirs. Due to the logistical, operational and environmental differences and the footprint and required weight needed for additional injection and production equipment, offshore chemical EOR processes are challenged by greater complexity and costs as compared to onshore applications of the same technologies. Chemical EOR commonly requires large volumes of injection chemicals, as well as demulsifiers to break produced water/oil emulsions and inhibitors to control scale, resulting in high shipment and storage costs. The use of seawater and/or produced water for injection of the chemicals into offshore fields mandates stringent processing of both streams to allow optimal injectivity, sweep efficiency, and chemical effectiveness in the reservoir. Offshore production of saleable oil and clean water requires space- and weight-efficient oil-water separation equipment. Currently, conventional methods for processing produced fluids fall short in both efficiency and compactness. High offshore drilling costs lead to relatively large well spacing and more difficulty monitoring the EOR subsurface process as well as to restrictions on the number of disposal wells. Finally, environmental restrictions limit the overboarding of toxic or poorly biodegradable EOR chemicals. Industry is currently investigating the limiting factors pertinent to offshore chemical EOR. As a result of these efforts, new enabling chemistries and technologies are being examined for improving surface operations to allow cost-effective offshore chemical EOR to be performed in an environmentally-sound and safe manner. Some of these recent chemical and fluids processing developments are described in this paper. 1. Introduction The primary depletion and secondary water flooding of oil reservoirs typically recover only 20-50% of original oil in place, and hence the majority of oil still remains trapped after the application of these conventional processes. The low oil recoveries from secondary water floods are the result of inefficient macroscopic sweep efficiencies due to lack of mobility control and poor microscopic displacement efficiencies caused by the capillary trapping of oil, attributed mainly to interfacial forces. By overcoming these inhibiting factors, chemical-based enhanced oil recovery (EOR) processes are presently considered as promising tertiary technologies for increasing oil recovery from depleted oil reservoirs. (Thomas 2006), (Manrique 2010) The chemical EOR processes, widely practiced in field applications, can be broadly categorized into two types; (1) polymer injection processes and (2) surfactant-based processes, in particular the alkaline-surfactant-polymer (ASP) injection process. Typical polymer injection processes utilize polymeric additives to flood water at concentrations ranging from about 500 to 2500 ppm. The addition of polymers to the injected water increases the aqueous phase viscosity thereby lowering the water-oil mobility ratio. This favorable mobility ratio aids in flood conformance control and hence improves the vertical (Figure 1) as well as areal sweep efficiencies. Polymeric additives to injected water also reduce porous media permeability and affect fractional oil flow for more efficient oil recovery. An added benefit is that much lower total volumes of water are produced for a given level of oil recovery.
Abstract Numerous single-phase flow and oil-recovery tests were carried out in unconsolidated sands and Berea sandstone cores using C14-tagged, hydrolyzed polyacrylamide solutions. The polymer-retention polyacrylamide solutions. The polymer-retention data from these flow tests are compared with data obtained from static adsorption tests. Polymer concentrations in produced water in Polymer-flooding tests were studied using various Polymer-flooding tests were studied using various polymer concentrations, slug sizes, salt polymer concentrations, slug sizes, salt concentrations, and different permeability sands. Results show that polymer retention by mechanical entrapment had a dominant role in determining the total polymer retention in short sand packs. However, the role of mechanical entrapment was less in the large-surface-area Berea cores. In oil-recovery tests, high polymer concentrations were noted at water breakthrough in sand-pack experiments, an indication that the irreducible water was not displaced effectively ahead of the polymer slug. However, in similar tests with Berea cores, a denuded zone developed at the leading edge of the polymer slug. polymer slug. The existence of inaccessible pore volume to polymer flow is shown both in sand packs and in polymer flow is shown both in sand packs and in sandstone cores. Absolute polymer-retention values show an almost linear dependency on polymer concentration. The effect of polymer slug size on absolute polymer retention is also discussed. Distribution of retained polymer in sand packs showed an exponential decline with distance. The "dynamic polymer-retention" values in short sand packs showed much higher vales than the ‘static packs showed much higher vales than the’ static polymer-adsorption" values caused by mechanical polymer-adsorption" values caused by mechanical entrapment. The mechanism of polymer retention in silica sands and sandstones is described, based on the observed phenomenon. Introduction It is widely recognized that, as polymer solution flows in a porous medium, a portion of the polymer is retained. It is evident that both physical adsorption and mechanical entrapment contribute to polymer retention. The question of the relative importance of these retention mechanisms has not been studied adequately. The effect of residual oil saturation on polymer retention and the polymer retention during the displacement of oil from porous media has also been studied inadequately. Mungen et al. have reported a few data on polymer concentration in produced water in oil-recovery tests. However, no produced water in oil-recovery tests. However, no comparison was made between polymer retention at 100-percent water saturation and at partial oil saturation. It has been shown that the actual size of the flowing polymer molecules, with the associated water, can approach the dimensions of certain smaller pores found in porous media. Therefore, an inaccessible pore volume exists in which no polymer flow occurs. In this study, the existence polymer flow occurs. In this study, the existence of inaccessible pore volume is shown clearly, both in sand and sandstone. Although polymer-retention values have been reported for various conditions, correlation is difficult because of the differing conditions of measurements. The effect of slug size, polymer concentration, salinity, and type of porous media on polymer retention has not been systematically studied. The purpose of this study was to develop answers to these questions, rather than to provide adsorption data for actual field core samples. For this reason, unconsolidated silica sands were used in most of the experiments reported. This permitted identical, uniform single-layer and multilayer porous media to be constructed for repeated experiments under varying test conditions. Some experiments were also carried out in Berea sandstone cores to determine whether sand-pack results can be extrapolated to consolidated sandstones. Using a C 14-tagged polymer provided a very rapid, simple, and accurate polymer-concentration determination technique. SPEJ P. 323