Influencing CEOR Performance by Optimizing Water Chemistry. Lisa Henthorne. Water Standard

Transcription

1 Influencing CEOR Performance by Optimizing Water Chemistry Lisa Henthorne Water Standard 1

2 Abstract Influencing CEOR Performance by Optimizing Water Chemistry A number of chemical enhanced oil recovery (CEOR) projects presently being implemented around the world require specialized water chemistry to optimize performance in the reservoir. The desire to use water quality, specifically the concentration of various inorganic salts, as a mechanism to influence oil recovery has become an area of interest in recent years with the advent of low salinity water injection. While low salinity water injection aims to change the wettability characteristics in the reservoir and tends toward a low salinity water combined with a consideration of divalent cation concentration to reduce chances of clay deflocculation, the range of desired CEOR water chemistry can vary to a much greater degree. Today, finding the technology and know-how to create the customized waters needed to implement the CEOR projects on the horizon is a challenge for the oil and gas industry. Because these unusual water compositions have never been required in any industrial or municipal application, the technology to separate, then pick and choose ions from seawater, brackish water or produced waters, has never been developed. Separation technologies such as membranes, distillation and ion exchange were developed to remove ions to achieve lower concentrations of ions. Examples include desalination, water softening, boiler feedwater and ultrapure water production. But selective removal of ions is more difficult, particularly when the feedwater source is highly saline such as seawater and many produced waters. To achieve their water quality goals, some CEOR projects have considered desalinating the source water then adding the desired salts along with the CEOR chemicals prior to injection. But based on the planned project capacities, the cost of salts can be more than $20 million per year for a relatively low salinity injection of 2,000 mg/l for KCl. Some projects have optimal salinities (based on surfactant performance) of more than 20,000 mg/l with extremely low hardness criteria. The cost of potentially adding salts to achieve these high salinity can cripple the economics for these projects. This paper describes the development and adaptation of specific membrane technologies and tools to enable water treatment to the desired unique compositions for various CEOR projects 2

3 around the world. Pilot testing has been accomplished at three test sites to compare actual membrane performance versus projected performance, to enable FEED design of the required systems. The paper also discusses some of the unique instrumentation and controls required to achieve the CEOR project performance goals, as well as the methods used to enable future flexibility in the treatment system to allow for different injectant water chemistries in future phases of the CEOR flood. Background Water-based Enhanced Oil Recovery (EOR) applications are increasing in number. Waterflooding, originally adopted for pressure maintenance purposes, is now maturing into a more profit-driven mechanism, which goes beyond secondary recovery to enhance oil production. Through alteration of the injection water chemistry, and in some cases, adding chemicals to improve conformance and miscibility between the oil and water, water-based EOR techniques, such as Low Salinity Flooding (LSF) and CEOR are finding success. As these EOR methods continue to develop and prove effective in increasing oil production, with some upfront planning, operators developing greenfield waterflood facilities can easily include optionality for EOR in the future. In addition, operators wanting to transition from existing conventional waterflooding to EOR, now have options to cost-effectively facilitate the transition, onshore and offshore. Moreover, some operators are thinking further outside the box, to use municipal or industrial wastewater as a source for EOR injection water. Though the Oil & Gas Industry is traditionally slow in adopting new technology, the relative low risk associated with the water treating technologies that enable these EOR mechanisms, coupled with the current oil price, is quickening the adoption rate. Waterflooding in its simplest form is injected into the reservoir formation to displace residual oil and maintain pressure. Its history reaches back to an original patent by William Richards in 1884, in which he recognized pressure on injected water would force oil to surrounding producing wells (PDHengineer, 2012). Based on empirical results, onshore flooding developed through the early 1900 s, and it was not until 1942 when Buckley and Leverett published the seminal paper on Mechanism of Fluid Displacement in Sands, that the theoretical basis and mechanisms of flooding were formulated. Through the mid-1900 s, waterflooding enjoyed a prosperous growth period, and then expanded offshore using seawater. Today, waterflooding is 3

4 standard in offshore oil production, and water handling and injection are often the single biggest operating cost for producers, with an estimated annual spend of $50 Billion (Sharma, M., 2011). Fortuitously, the pre-existence of waterflooding infrastructure in aging fields throughout the world, enables a cost-effective transition to water-based EOR implementation. Water Treating for Waterfloods Historically, water treatment has had a primary role in three key areas of waterflooding: source water filtration and deaeration, sulphate reduced flooding, and produced water treatment. In general, unit operations used in water treatment facilities vary depending on whether they are located onshore or offshore, and it usually dictates the water composition. Onshore, water resources are often limited and operators must use produced water reinjection. Offshore, seawater is the primary water resource, and space and weight are primary constraints. Yet, seawater is recognized as having potentially value-eroding properties. The most widely recognized problem is scale formation from chemical incompatibility of the injected seawater (high sulphate), and the original formation brine and reservoir rock containing barium and strontium. In reservoirs that contain a substantial barium or strontium content, seawater injection will cause the naturally occurring sulphate contained in the seawater to precipitate with the barium and/or strontium, and this effect can eventually diminish the output of the production wells. In addition, sulphate-reducing bacteria in some reservoirs can feed on sulphate in seawater, thereby producing hydrogen sulphide and souring the well or reservoir. As a result, sulphate is often removed from the seawater in a facility process referred to as the Sulphate Removal Package (SRP), using specialized Nanofiltration (NF) membranes that maintain a high salinity. Dow FilmTec and Marathon Oil first introduced this membrane system in Historically, Dow FilmTec has been the only manufacturer of SRP membranes, but recently other manufacturers have successfully developed similar membranes, which are now operational offshore. By the end of 2012, approximately 70 SRP systems were either online or under construction for offshore production facilities around the world. Historically, due to space and weight constraints, a major challenge in considering offshore EOR is the retrofit cost to transition from an SRP system to a facility capable of meeting the EOR water quality specifications. 4

5 Low Salinity Waterflooding One of the fundamental elements in understanding water-based EOR is recognizing the relationship between the oil, the water, and the rock within the reservoir. Typically, oil reservoirs contain a degree of formation water of varying salinity. The wettability of reservoir rock is defined as the portion of the rock surface coated with adsorbed hydrocarbons. For increasing oil wetness, the oil prefers to stick to the rock and flow less easily relative to water. One of the methods to increase oil recovery is to shift the reservoir toward more water wetness by manipulating the ionic water composition at the interface point between the oil and rock. Since the late 1990s, there have been numerous laboratory tests and field studies, where injection of low salinity water has resulted in increased oil recovery. The University of Wyoming and BP were early pioneers of the concept. BP has demonstrated the viability of LSF on sandstone core samples and in the Alaskan North Slope fields. BP has since trademarked the process as LoSal TM. Shell Oil Company has also progressed the concept. Supportive testing and analysis of low salinity application to limestone reservoirs has been undertaken by the University of Stavanger and Aramco. In considering low salinity injection in sandstone, clay stability of the reservoir must be considered. Injecting fresh water or water with too low a salinity can destabilize clays, based on the clay composition in the reservoir. Research has been undertaken to describe the suitability of injection water composition for various clay types (Ayirala et al, 2010, Ligthelm et al, 2009, Scheurerman and Bergersen, 1990), indicating smectite and montmorillonite clays to be the most sensitive. The relationship between total cations and percent divalent cations, on an equivalence basis, provides guidance to the degree of clay sensitivity and suitability of various water compositions for injection. Therefore, the concentration of divalent cations, such as magnesium and calcium, play an important role in clay stability. The mechanism of low salinity flooding is depicted simplistically in Figure 1; the process of which can be described as follows: 1. Polar molecules in reservoir oil are attracted to the negatively charged clay surface. Divalent cations (calcium, magnesium) act as bridges between the negatively charged molecules in the oil and the negatively charged clay surface. 5

6 2. Low salinity water reduces the electrostatic forces holding the oil to the rock, resulting in the release of oil from the rock surface. 3. When low salinity water is injected, the ion exchange equilibrium changes, and bound oil becomes mobile and oil recovery increases. LSF is anticipated to increase oil recovery in the range of 5-10% of Original Oil in Place (OOIP), based on recent publications (Austad et al, 2010, Ayirala et al 2010, Seccombe et al, 2010, Sorbie et al, 2010, Vledder et al, 2010, Ligthelm et al, 2009, Webb et al 2008, Lager et al, 2008). In examining the preferred water chemistry in full-scale LSF projects under development, a wide range of variability is seen, as a function of the reservoir and oil characteristics. Preferred salinity levels range from 2,000 to 8,000 mg/l, hardness varies from 10 to 200 mg/l, while sulphate ranges from 20 to 60 mg/l. The ability to create these selective blends will be discussed in the subsequent sections. Figure 1: Water-Oil-Rock Interfacial Characteristics Chemical Enhanced Water Injection CEOR is also emerging as a vital method to increase recoverable oil from aging reservoirs; however, economics and the achievable, incremental, and recoverable oil will dictate its widespread adoption. Water chemistry of the injection water plays an important role in the effectiveness and cost of CEOR. CEOR programs can utilize alkali, surfactant, or polymer, or some combination of same, such as Alkali-Polymer (AP), Surfactant-Polymer (SP), and Alkali- Surfactant-Polymer (ASP). In polymer floods, using partially Hydrolyzed Polyacrylamides 6

7 (HPAM), it is well established the achievable viscosity for a given polymer concentration is a function of the injection water salinity, with divalent cations having a more detrimental impact than monovalent ions. Studies have shown (see Figure 2), that five to ten times less HPAM is required when using desalinated or lower salinity water compared to seawater, resulting in an equivalent cost savings related to polymer consumption. In surfactant flooding, the relationship between the injection water chemistry and the effectiveness of the flood is a more complex equation. Considerable research is ongoing to predict optimal salinities for surfactant flooding and the added benefit of using salinity gradients through the life of the surfactant flood. Lastly, alkali addition to either a surfactant and/or polymer flood requires the injection water be softened, to prevent calcium and magnesium carbonate precipitation in the case when sodium carbonate is the source of cost-effective alkali. Complicating matters further, the injection water salinity must be kept to a level sufficient to prevent clay swelling in the reservoir (similar to low salinity flooding), and sulphate levels must be low enough to prevent precipitation of the sparingly soluble salts of barium or strontium, if present. Typically, sandstone reservoirs are most frequently utilized for CEOR due to the higher permeability of sandstone compared to limestone reservoirs. The majority of the CEOR technologies have been tested at pilot and commercial scale on sandstone lithology (Alvardo, V. and Manrique, E. 2010). Increased oil recovery from CEOR floods is anticipated to range from 5-35% of OOIP, depending on the reservoir characteristics, and the type and duration of flooding. The preferred water chemistries in CEOR floods vary tremendously, from low salinity to very high salinity, but generally, low hardness and low sulphate are preferred. 7

8 Normalized Polymer Concentration (dimensionless) Influencing CEOR Performance by Optimizing Water Chemistry Figure 2: Polymer concentration required to achieve preferred viscosity at varying salinity (Ayirala, S., Ernesto, U., Matzakos, A., Chin, R., Doe, P., van Den Hoek, P., 2010) sec-1 and 25 C 6 2 sec-1 and 46 C Injection Water Salinity (ppm) Challenges in Water Treating for LSF and CEOR The ionic composition of injection water to optimize flood performance in LSF and CEOR applications usually requires selective ion removal, that is, certain cations and anions must be removed, while others are left behind. NF membranes are a proven technology for sulphate removal for SRP treatment; therefore, are well accepted by the Oil & Gas Industry. Figure 3 provides a general description of the types of removal capabilities of different membrane products. It is to be noted that membrane filtration technologies, microfiltration, and ultrafiltration, remove suspended solids, but not dissolved salts. Only the family of NF and Reverse Osmosis (RO) can effect removal of dissolved salts; therefore, they are the membranes needed for selective ion removal. However, the membrane filtration technologies are excellent pretreatment unit operations to use upstream of NF or RO (Henthorne, 2010; Movahed, 2007). 8

9 Figure 3: Membrane treatment technologies as a function of rejection by molecular weight, size, and types of contaminants The challenges in developing the range of specific water chemistries identified as preferable for LSF and CEOR include: Leaky membranes that allow selective salt passage are not in demand in the municipal or industrial membrane market, other than SRP membranes. Softening-type NF membranes have not been developed for seawater treatment Though the membrane industry is interested in the EOR market, it is not currently of sufficient size to warrant R&D for new membrane technologies Adaptation of proven municipal-type membranes into EOR applications that operate under vastly different conditions and configurations, requires piloting and investment by users Oil & Gas Industry projects are inclined to have exacting timelines that do not allow for technology development and trials needed to achieve required Technology Readiness Levels (TRL) 9

10 The EOR project water quality specifications have narrow bands of allowable fluctuations. Inherently, membranes produce a varying permeate quality as a function of feedwater temperature and composition, and membrane life Oil & Gas Industry availability factors, design specifications and HSE requirements, differ from the municipal water industry The design drivers of facilities in Oil & Gas Industry applications, differ greatly from the typical municipal or industrial water industry, requiring a paradigm shift in design values Many of the preferred water chemistries requested for EOR projects have never before been created using currently available technology Membrane systems are designed to provide up to a specific salinity (or salt level) under all operating conditions, while EOR systems may have both minimum and maximum requirements In EOR applications, access to different water chemistries can optimize oil recovery, as the field transitions between different flood phases, which requires the water treating facilities to provide a range of water quality Solutions to Effect Customizing Water Chemistry Ideally, one type of water treatment system could be developed to address the challenges previously described. The ideal characteristics would include the ability to: Produce a wide range of product water quality, from low to high salinity, from low to medium hardness and sulphate Fine-tune the product quality as a function of changing conditions, such as fluctuations in feedwater temperature and composition, and the changing performance of the membranes over their three to five year life Change output quality during different phases of injection, and turndown/up output capacity, as needed, as a function of blending of produced water or other needs Automatically change the output water chemistry, on demand Achieve a TRL for commercial application Maintain a low weight and compact footprint, for ease in slotting into traditional SRP allocated spacing on greenfield projects, and retrofitting brownfield systems 10

11 The H 2 Ocean Spectrum TM Technology aims to achieve these ideals. Pilot testing in support of upcoming full-scale LSF and CEOR projects, demonstrated its capabilities and confirmed membrane performance and tuning aspects of the system, and has achieved a minimum TRL 5. Figure 4 describes the achievable water quality available from one H 2 Ocean Spectrum TM Technology system, while Figure 5 demonstrates the capability of the membranes to achieve expected hardness, sulphate and salinity rejection, based on pilot results. Due to its predominant use of membrane technology for both filtration and selective salt removal, the system maintains a compact footprint and weight, for ease of offshore adoption. Figure 4. Cases of different achievable water quality from one H 2 Ocean Spectrum TM Technology system 11

12 Figure 5. Salt rejection capability of a specific NF membrane product piloted in the H 2 Ocean Spectrum TM Technology system Conclusions Water-based EOR methods are proving viable in pilots and full-scale applications around the world. The ability to customize the water chemistry for injection in the EOR applications will improve EOR performance and reduce costs. The Oil & Gas Industry needs new technologies to meet the atypical needs of the water treating facilities for water-based EOR applications. For offshore applications, space and footprint are also important drivers for adoption of the technologies. The H 2 Ocean Spectrum TM Technology was developed to meet the overarching needs associated with cost-effective implementation of EOR in the Oil & Gas Industry, and is currently being adopted for full-scale EOR facilities. 12

13 References Alvardo, V. and Manrique, E Enhanced Oil Recovery: An Updated Review, Energies 3(9), , August Austad, T., RezaeiDoust, A., and Puntervold, T. Chemical Mechanism of Low Salinity Water Flooding in Sandstone Reservoirs, SPE Paper presented at the SPE Improved Oil Recovery Symposium, April Ayirala, S., Ernesto, U., Matzakos, A., Chin, R., Doe, P., van Den Hoek, P A Designer Water Process for Offshore Low Salinity and Polymer Flooding Applications, SPE Paper presented at SPE Improved Oil Recovery Symposium, April Henthorne, L., Trends in Pretreatment for Seawater Reverse Osmosis, Water Conditioning and Purification, November Lager, A., Webb, K., Black, C., Singleton, M., and Sorbie, K Low Salinity Oil Recovery An Experimental Investigation, Petrophysics Journal, Vol. 29, No. 1. Ligthelm, D., Gronsveld, J., Hofman, J., Brussee, N., Marcelis, F., and van der Linde, H.A Novel Waterflooding Strategy by Manipulation of Injection Brine Composition, SPE Paper presented at SPE Improved Oil Recovery Symposium, April Movahed, B., Pretreatment for Membrane Processes, American Membrane Technology Association fact Sheet, PDHengineer.com, Waterflood History and Design Fundamentals, Course No Online Publication Scheuerman, R. and Bergersen, B. Injection-Water Salinity, Formation, Pretreatment, and Well- Operations Fluid-Selection Guidelines, Journal of Petroleum Technology, July Seccombe, J., Lager, A., Webb, K., Jerauld, G., and Fueg, E Improving Waterflood Recovery: LoSal EOR Field Evaluation, SPE Paper presented at SPE Improved Oil Recovery Symposium, April