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This research focuses on membrane-separation efficiencies by adjusting the ionic composition of deoiled produced water (PW) and evaluates the possibility for smartwater production from PW for enhanced oil recovery (EOR) in carbonate reservoirs. Key characteristics of smartwater for carbonate reservoirs are increased concentrations of divalent ions and low concentrations of monovalent ions compared with seawater.
In this research, PW was pretreated with media filters, which resulted in 96 to 98% oil removal. This deoiled PW was used as feed for nanofiltration (NF) membranes. Combinations of NF retentate with seawater as feed and NF permeate from PW were considered. PW NF permeate, mixed with seawater spiked with multivalent ions, sulfate (SO2-4), or phosphate (PO3-4), is expected to alter the wettability of oil reservoirs.
NF-membrane performance was evaluated in terms of flux and the separation efficiencies of the key scaling ions calcium (Ca) and barium (Ba). The tested membranes removed 60% of Ca2+ and 53% of Ba2+, thereby reducing the scaling tendency. No membrane fouling was observed during the experiments.
NF-treated PW was analyzed for solubility of calcium carbonate (CaCO3). The results showed no Ca dissolution, which could affect chalk-reservoir compaction. This research also reflects the use of nonprecipitating PO3-4 for smartwater production, simultaneously decreasing the Ba concentration and the scaling potential of PW. The results obtained conclude that spiking PO3-4 below 12 mM showed no indication of chalk dissolution during equilibration tests at room temperature. Experiments performed with 44 mM of PO3-4 resulted in calcium phosphate [Ca3(PO4)2] precipitation.
A process scheme is proposed for smartwater production by ionic selection from seawater and PW at an operating pressure of 18 bar. Energy-consumption analysis for smartwater production before membrane treatment concluded NF to be economic over other desalination technologies. The power consumed by NF membranes for smartwater production at 18 bar is calculated at 0.88 kWh/m3, whereas the power consumed is 51.22 and 103.52 kWh/m3 for reverse osmosis (RO) and multistage flash distillation (MSF), respectively.
The PDF file of this paper is in Russian.
The production experience from the Statfjord Field on the Norwegian Continental Shelf is one of the greatest adventures in modern oil and gas history. After achieving very high oil recovery factor using a predominant drainage strategy with pressure maintenance by water and gas injection, the drainage strategy in the field has since 2007/2008 been changed to reservoir depressurization.
Prior to depressurization start-up, the field has produced about 652 million Sm3 (4.1 billion bbl) oil and 187 billion Sm3 gas. Currently, the field is producing at an oil rate of approximately 5 300 Sm3/d and a gas rate of about 11 million Sm3/d. Estimates indicate that successful implementation of the new drainage strategy will continue and lead to an ultimate oil recovery of higher than 67% and a significant additional gas production, as a result of the depressurization process. In addition, the field life will be extended from 2009 to 2025, and this will contribute to lifetime extension of the attached satellite fields.
The main purpose of this paper is to provide a description of the multidisciplinary approach used for evaluation and planning of the Statfjord Late Life (SFLL) with reservoir depressurization, share learnings from depressurization start-up and address challenges, uncertainties and opportunities.
The production experience from the Statfjord Field on the Norwegian Continental Shelf is one of the greatest adventures in modern oil and gas history. After achieving very high oil recovery factor using a predominant drainage strategy with pressure maintenance by water and gas injection, the drainage strategy in the field has since 2007/2008 been changed to reservoir depressurization. Prior to depressurization startup, the field has produced about 652 million Sm 3 (4.1 billion bbl) oil and 187 billion Sm 3 gas. Currently, the field is producing at an oil rate of approximately 5 300 Sm 3 /d and a gas rate of about 11 million Sm 3 /d. Estimates indicate that successful implementation of the new drainage strategy will continue and lead to an ultimate oil recovery of higher than 67% and a significant additional gas production, as a result of the depressurization process. In addition, the field life will be extended from 2009 to 2025, and this will contribute to lifetime extension of the attached satellite fields. The main purpose of this paper is to provide a description of the multidisciplinary approach used for evaluation and planning of the Statfjord Late Life (SFLL) with reservoir depressurization, share learnings from depressurization startup and address challenges, uncertainties and opportunities.
Imbibition only relative permeability is commonly used to model water influx in water-drive gas reservoirs, however an aquifer is rarely strong enough to maintain constant pressure support. Continued pressure depletion in the part of the reservoir swept with watercauses expansion and remobilisation of trapped gas behind the waterfront. This paper presents a reservoir simulation study on modelling the expansion and remobilisation of trapped gas due to pressure depletion as secondary drainage flow using relative permeability hysteresis.
Previous studies in literature on relative permeability show the secondary drainage curve during blowdown is below the primary imbibition curve. This is based on field cases and core experimental studies, which establish the existence of a gas remobilisation threshold above residual saturation to reconnect the gas phase. Commonly used hysteresis models by
The conclusion of this study is that the standard formalisms used to model relative permeability hysteresis (Killough, Carlson) should not be used to model trapped gas remobilisation due to blowdown as they do not incorporate a gas remobilisation threshold and a secondary drainage curve underlying the primary imbibition curve. By assuming no mobility threshold above residual gas saturation, the total recovery of residual gas will be overestimated. Instead, by adopting the ODD3P hysteresis model, gas production will be lower and water production higher due to the correct use of secondary-drainage relative permeability curves in a gas reservoir invaded by water. This will lead to a significant improvement in results from reservoir simulation and the subsequentevaluation of trapped gas recovery.
The expansion and remobilisation of residual or trapped gas saturations has a major impact on the prediction and/or matching of production and pressure response from a reservoir. This study intends to understand these impacts and serve as a preliminary guideline in modelling trapped gas expansion and remobilisation as secondary drainage flow, which is applicable to many water-drive gas reservoirs.
A Residual Oil Zone (ROZ) is a naturally waterflooded reservoir at residual or near residual oil saturation, technically recoverable only through unconventional methods. The development of ROZs is extensively pursued in the Texas Permian Basin. Several successful ROZ CO2 Enhanced Oil Recovery (CO2-EOR) projects indicate enormous resource potential for these emerging oil plays. Another approach, called Depressurizing the Upper ROZ (DUROZ), was recently proposed and is currently under extensive investigation. This study offers a mechanistic understanding of DUROZ and investigates the factors affecting its viability and performance.
DUROZ refers to the progressive reduction of reservoir pressure through the withdrawal of large volumes of water from a horizontal well in the upper section of ROZ. When reservoir pressure falls below the saturation pressure, gas bubbles liberate from capillary-trapped oil and develop into a continuous gas phase. Consequently, the oil phase may also become mobile beyond waterflood residual oil saturation. We history-match the oil and water production from twoDUROZ producers in the upper San Andres dolomite using a tuned reservoir simulation model. To properly capture the rock and fluid interaction, the relative permeability data are tuned with the experimental core datafrom the San Andres ROZ. Extensive experimental studies have highlighted a substantial difference between relative permeabilities measured under external drive and solution gas drive. We define two sets of relative permeabilities: an original set based on the external drive experiments and the relevant correlations, and a modified set for modeling production under solution gas drive.
Our results show that even for the most optimistic relative permeabilities, the reservoir initial oil saturation should be at least 20% above the residual oil saturationin order to match the oil cuts of the reported DUROZ producers. This shows inconsistencies in use of the term "residual oil"zone by the industry in the Permian Basin. In other words, although DUROZ shows potential for production beyond waterflood residual oil saturation, the documented cases are unlikely to be true ROZ producers and are more likely completed in the Transition Zone (TZ) or near-ROZ. Finally, a discussion on the operational risks and technical considerations associated with DUROZ, including water disposal, infrastructure and facility requirements, and modeling limitations, is presented.
Abuah, Nnamdi L. (The Shell Petroleum Development Company Nigeria Limited) | Olugbenga, Daodu (The Shell Petroleum Development Company Nigeria Limited) | Adam, Sedqwick M. (The Shell Petroleum Development Company Nigeria Limited) | Chiejina, Leo (The Shell Petroleum Development Company Nigeria Limited) | Bamidele, Taiwo (The Shell Petroleum Development Company Nigeria Limited) | Onuigbo, Nweze C (The Shell Petroleum Development Company Nigeria Limited) | Stella, Egwim (The Shell Petroleum Development Company Nigeria Limited) | Florence, Ifeanyi-Onah (The Shell Petroleum Development Company Nigeria Limited) | Onyedikachi, Okereke (The Shell Petroleum Development Company Nigeria Limited) | Bassey, Imaobong (The Shell Petroleum Development Company Nigeria Limited) | Noah, Ebogomo (The Shell Petroleum Development Company Nigeria Limited) | Igban, Kalu (The Shell Petroleum Development Company Nigeria Limited)
Beta Integrated Oil and Gas plant is the major supplier of domestic gas to the Lima power plant which provides 16% of the available power to the Nigerian national grid. Efforts are made to ensure that down times in the plant are reduced because of the huge impact to domestic gas supply in the country. Between 2014 and 2015, multiple tripping had been observed on the transfer pump at the Beta gas plant. Laboratory analysis of the recovered solid deposits in addition to scale simulations of the hydrocarbon fluid confirmed the presence of calcium carbonate scale (85.2%wt). Although the culprit well was identified, a cost-effective surface chemical solution was immediately deployed upstream of the facility which significantly reduced the export pump downtime due to scaling and clogging. The overall treatment option adequately mitigated the calcium carbonate scale observed and also led to significant savings in pump maintenance of about a million dollars.
This paper will be discussing the problem and underlying restrictions faced by the multidisciplinary team, problem solving approaches considered as well as the solution employed by deploying Phosphate Ester based chemical scale inhibitor.
The scale inhibitor is specially formulated to prevent the formation of calcium carbonate, calcium sulphate, barium sulphate and strontium sulphate scales in producing wells, water injection systems and saltwater disposal systems.
One major consideration in the choice and use of the product is the cost effectiveness of the product, its potency and suitability at effectively mitigating the calcium carbonate scaling in the gas plant. It was successfully qualified in the lab for use with MIC of 10-20ppm and has been previously deployed in our deep water facility. Laboratory tests indicate it is effective in produced water with iron and high bicarbonate content as is the case for Beta gas plant. In addition, laboratory tests indicate it does not encourage deposition of naphthenates in produced water as is observed with some phosphate based scale inhibitors. The product is also readily available in-country hence no long delivery lead time challenges, besides there is significant cost and logistics value to be realized from its deployment in Beta oil and gas plant.
Nair, Remya Ravindran (Department of Mathematics and Natural Science) | Protasova, Evgenia (Department of Mathematics and Natural Science) | Bilstad, Torleiv (Department of Mathematics and Natural Science) | Strand, Skule (Department of Petroleum Engineering, University of Stavanger)
Produced water (PW) management and reuse of PW has economic and environmental benefits compared to PW discharge. This research focuses on membrane separation efficiencies in adjusting the ionic composition of de-oiled PW and evaluating the possibility for smart water production from PW for enhanced oil recovery. Key characteristics of smart water for carbonate reservoir is increased concentration of divalent ions and depletion of monovalent ions.
Dual media is used for oil removal from PW. De-oiled PW is feed for Nanofiltration (NF) membranes for separation of barium and calcium ions. Combination of NF retentate with seawater (SW) as feed and NF permeate from PW is also considered. PW permeate is mixed with SW spiked with determining multivalent ions, sulfate or phosphate, which alter wettability of oil reservoirs.
Currently, smart water is produced by adding chemicals to fresh water or low total dissolved solids (TDS) water produced by reverse osmosis (RO) or flash distillation. Using de-oiled PW as feed to NF will reduce power consumption, footprint and chemicals. PW can be reinjected into reservoirs after removing scale-causing ions. By injecting low barium and calcium PW brines, the frequency of scale squeezes will decrease. Membrane performance is evaluated for flux and separation efficiencies of calcium and barium. Barium concentrations in synthetic PW is increased 20 times the original concentration in Tor Field in North Sea, for evaluating NF separation efficiency. Negligible amount of barium is present in NF permeate at pressures of 8-12 bars resulting in a permeate flow rate of 200 L/h for a membrane area of 2.6 m2.
Increased sulfate concentration in smart water enhances recovery by 40 % of original oil in place. However, BaSO4 scalingcan be initiated even with negligible barium concentration if high sulfate level is present in the injected brine. The novelty of this research resides in the use of non-precipitating phosphate replacing sulfate for smart water production, simultaneously decreasing barium concentration and scaling potential of PW. However, precipitation of calcium occurred in presence of high concentration of phosphate. Power consumed by NF membranes for smart water production is calculated at 0.37 kWh/m3.
Injection water-induced formation damage evaluation is considered critical in a low-permeability (2 md) oil reservoir development because of the potential bridging of narrow pore throats by in-situ scale precipitates. This problem can be mitigated with processed low-salinity water, albeit at significantly high capital expenditure associated with water processing facility that could erode the economic margin of the project. Laboratory fluid compatibility tests and software simulation were therefore conducted to appraise the risk of inorganic scale deposition during water injection in an undeveloped carbonate reservoir with high-salinity formation brine (TDS 205 g/L). The laboratory experiments were initially carried out with both synthetic and actual field samples including formation water extracted from pressurized downhole fluid tester. Coreflood and fluid-fluid compatibility tests were carried out at estimated bottom-hole temperature of 150 F and pressure of 1,000 psi. Comprehensive mixed-brine simulation software was also used to determine the inorganic scaling tendency expected with the use of seawater, produced water and diluted produced water for the planned injectors. The study identified an inherently high calcium sulfate risk associated with the planned seawater injection in the new reservoir while the highest combined inorganic scale precipitation was observed at approximately 1:1 ratio for the formation brine-seawater mixture. This paper discusses the laboratory fluid compatibility experiments and scale prediction analysis for different injection water utilization while providing an insight into the potential impact of scale risks associated with seawater injection in an onshore development reservoir with high divalent-salt content formation brine.
Water flooding has been widely used in the industry as a secondary recovery technique to improve recovery from oil reservoirs. One of the major operational challenges is addressing the compatibility between injected water and formation water in order to proactively lower the probable risk of scale formation near wellbore. A thorough investigation was conducted to evaluate the probability of scale formation and identify the effective mitigation options for a Central Arabian incremental development project.
A holistic approach was implemented at this study to achieve the objective through reviewing analogue reservoirs, running numerical predictions of scale tendency, carrying out laboratory experiments to evaluate the compatibility of the formation water with the injected mix water and conducting in-situ coreflood experiments to quantify the potential risk of formation damage.
This study identified an inherently high calcium sulfate scale risk associated with the planned seawater injection in the new reservoir development and within the surface production fluid process facilities. Appropriate scale mitigation options including the potential impact of an injection seawater sulfate removal process facility will be discussed in this paper.
RS field is located in the Central Arabia and has three oil bearing carbonate reservoirs - two with high-permeability (>100 md) and an underlying low-permeability (average ~ 2 md) one with elongated, north-south trending, asymmetrical anticline structure and a tight aquifer as the lower boundary. Field came on stream in 2009 with production capacity of 1.2 MMBPD and water injection of ~2 MMBWD after initial development of the high-permeability reservoirs. Incremental development project which involves drilling of additional oil producers, power water injectors (PWI) and observation wells is currently planned with part of the production increment expected from the low-permeability reservoir (DL). The new reservoir development is expected to be more challenging than the shallower reservoirs with significantly higher permeability and gross thickness.
Current water injection along the flanks of the field utilizes processed Arabian Gulf seawater (SW) and produced water/disposal water (DW) from the offset reservoirs. Since injection water breakthrough, only minor scaling incidents have been observed in the field with bottom-hole samples of organic and inorganic scales recovered from two wells while logging PLT. Produced water is often used as injection fluid due to the reduced risk of formation damage associated with incompatible fluids since it must be disposed with or without additional clean-up. Mixing waters from different sources exacerbates the risk of scaling. Seawater is obviously the most conveniently abundant source for offshore production facilities, and when pumped inshore for use in land fields. In the absence of non-saline shallow aquifer water which has the greatest advantage of purity, only DW from offset reservoirs and SW from seawater plant were considered for the DL water injection.
Injection-water chemistry plays a significant role in the impact of several improved-oil-recovery (IOR) and enhanced-oil-recovery (EOR) processes. Recently, advanced waterfloods through the tailoring of injection-water salinity and composition have received good attention in the oil industry for both sandstone and carbonate reservoirs. However, the importance of injection-water chemistry has not received its due attention as a whole in the IOR/EOR business because published studies in this area are distributed sparsely in bits and pieces without much relation to establish the strong connection. Also, injection-water-chemistry effects in certain EOR areas remain largely unexplored, even though they look somewhat promising. Moreover, the existing literature lacks a clear definition of injection-water-chemistry requirement guidelines for all IOR/EOR processes, including some of the newer processes that currently either are being practiced or are in research. In this paper, we provide a comprehensive review of more than 100 papers published during the past several decades in this subject area. The objectives of this review study are to provide an overview of smart-waterflooding technology; to describe important roles played by injection-water chemistry in the IOR/EOR business, with supporting examples; to extend the applicability of the smart-water concept to different IOR/EOR processes; and to develop the desired injection-water-chemistry requirement guidelines for IOR/EOR. The review analyses presented in this paper indicate that injection-water chemistry is important everywhere in the IOR/EOR business and is applicable not only to advanced waterfloods, but also to most of the recovery processes among the three major EOR types. These EOR processes include polymer flooding, alkaline-surfactant-polymer flooding, low-salinity surfactant flooding for sandstones, dilute-surfactant flooding for carbonates, carbonated waterflooding, miscible carbon dioxide (CO2) water-alternating-gas (WAG) flooding, and steamflooding. Injection waters of optimized salinity and ionic composition can also combine synergistically with several other EOR processes to result in higher incremental oil recoveries. Lower-salinity waters have a beneficial effect in polymer, surfactant, dilute-surfactant, and carbonated waterfloods, to yield better oil recoveries when compared with high-salinity water. The use of smart water for tertiary miscible CO2 WAG floods and carbonated waterflooding appears promising; however, it requires additional research to clearly distinguish and determine smart-water effects in these processes. The review analyses are finally extended to develop the desired injection-water-chemistry requirements for all individual IOR/EOR processes currently known. The findings of this study also put forward two major recommendations for consideration by the industry: (1) there is a need for close collaboration between water and oil industries to develop fit-for-purpose water-treatment solutions for addressing IOR/EOR injection-water-chemistry requirements, and (2) some thought should be given to develop “water chemistry” as a specialty discipline within the oil industry, for better integration of this emerging focus area with other key surface- and subsurface-related disciplines to effectively improve upon the IOR/EOR upstream value chain.