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Results
Microfluidics for Carbonate Rock Improved Oil Recovery: Some Lessons from Fabrication, Operation, and Image Analysis
Duits, Michel H. G. (University of Twente, Physics of Complex Fluids Group (Corresponding author)) | Le-Anh, Duy (University of Twente, Physics of Complex Fluids Group) | Ayirala, Subhash C. (Exploration and Petroleum Engineering Center - Advanced Research Center (EXPEC ARC)) | Alotaibi, Mohammed B. (Exploration and Petroleum Engineering Center - Advanced Research Center (EXPEC ARC)) | Gardeniers, Han (University of Twente, Mesoscale Chemical Systems Group) | Yousef, Ali A. (Exploration and Petroleum Engineering Center - Advanced Research Center (EXPEC ARC)) | Mugele, Frieder (University of Twente, Physics of Complex Fluids Group)
Summary After the successful implementation of lab-on-a-chip technology in chemical and biomedical applications, the field of petroleum engineering is currently developing microfluidics as a platform to complement traditional coreflooding experiments. Potentially, microfluidics can offer a fast, efficient, low-footprint, and low-cost method to screen many variables such as injection brine composition, reservoir temperature, and aging history for their effect on crude oil (CRO) release, calcite dissolution, and CO2 storage at the pore scale. Generally, visualization of the fluid displacements is possible, offering valuable mechanistic information. Besides the well-known glass- and silicon-based chips, microfluidic devices mimicking carbonate rock reservoirs are currently being developed as well. In this paper, we discuss different fabrication approaches for carbonate micromodels and their associated applications. One approach in which a glass micromodel is partially functionalized with calcite nanoparticles is discussed in more detail. Both the published works from several research groups and new experimental data from the authors are used to highlight the current capabilities, limitations, and possible extensions of microfluidics for studying carbonate rock systems. The presented insights and reflections should be very helpful in guiding the future designs of microfluidics and subsequent research studies.
- North America > United States (1.00)
- Asia > Middle East (0.67)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.81)
- Geology > Mineral > Carbonate Mineral > Calcite (0.53)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Flow-Through Experiments of Reactive Ba-Sr-Mg Brines in Mons Chalk at North Sea Reservoir Temperature at Different Injection Rates
Andersen, Pรฅl รstebรธ (Department of Energy Resources, University of Stavanger (Corresponding author)) | Herlofsen, Sander Sunde (Department of Energy Resources, University of Stavanger) | Korsnes, Reidar Inge (Department of Energy and Petroleum Engineering, University of Stavanger) | Minde, Mona Wetrhus (Department of Mechanical and Structural Engineering and Materials Science, University of Stavanger)
Summary North Sea Chalk reservoirs in Norway are potential candidates for enhanced hydrocarbon recovery by modifying the injected brine composition. This work investigates how barium (Ba), strontium (Sr), and magnesium (Mg) brines interact when injected into chalk. Ba and Sr are often associated with mineral precipitation and occur in formation water, while Mg is present in seawater, commonly injected in chalk. Relatively clean (>99% calcite) outcrop chalk cores from Mons, Belgium, were flooded at 130ยฐC in triaxial cells with four brines containing 0.12 mol/L divalent cations, either 0.06 mol/L Sr and Ba, 0.06 mol/L Sr and Mg, or 0.12 mol/L Ba or Sr. Each brine was injected in a separate core, with 100โ150 pore volumes (PV). The injection rate varied between 0.5 and 8 PV/D. Produced brine was analyzed continuously and compared with the injected composition. After flooding, the cores flooded with only Ba or only Sr were cut into slices and analyzed locally in terms of scanning electron microscopy (SEM), matrix density, specific surface area (SSA), and X-ray diffraction (XRD). In all experiments, the produced divalent cation concentration was reduced compared with the injected value. The total reduction of injected cation concentration closely equaled the produced Ca concentration (from calcite dissolution). When flooding 0.12 mol/L Sr, the Sr concentration depleted 55%, while when flooding 0.12 mol/L Ba, 15% Ba depleted. When injecting equal concentrations of Ba and Sr, 40% Sr and 7% Ba depleted, while with equal concentrations of Mg and Sr injected, ~50% Sr was retained and almost no Mg depleted. Sr appeared to dominate and suppress other reactions. There was less sensitivity in steady-state concentrations with variation in injection rate. The similar modification of the brine regardless of residence time suggests the reactions reached equilibrium. Cutting the cores revealed a visually clear front a few centimeters from the inlet. The material past the front was indistinguishable from unflooded chalk in terms of density, SSA, microscale structure, porosity, and composition [XRD and SEM-energy-dispersive spectroscopy (EDS)]. The material near the inlet was clearly altered. Images, XRD, SEM-EDS, and geochemical simulations indicated that BaCO3 and SrCO3 formed during BaCl2 and SrCl2 flooding, respectively. Geochemical simulations also predicted an equal exchange of cations to occur. The matrix densities, porosities, and the distance traveled by the front corresponded with these minerals and suggested that the chalk was completely converted to these minerals behind the front. It was demonstrated that Ba, Sr, and Mg brines and their mixtures can be highly reactive in chalk without clogging the core, even after 100 + PV. This is because the precipitation of minerals bearing these ions is associated with simultaneous dissolution of calcite. The Ca-, Ba-, and Sr-mineral reactions are effectively in equilibrium. Previous investigations with MgCl2 (in pure and less pure chalk, at 130ยฐC) show injection rate-dependent results (Andersen et al. 2022) and smoother alterations [Mg precipitation was seen from inlet to outlet (Zimmerman et al. 2015)], indicating that Mg-mineral reactions at same conditions have a longer time scale. The limited distance mineral alteration has occurred, suggesting that adsorption processes, happening in parallel, can explain previous observations (Korsnes and Madland 2017) of Ba and Sr injection strengthening chalk. Flushing out formation water with these ions during injection may be a new water-weakening mechanism.
- North America > United States (1.00)
- Europe > Norway > North Sea (0.70)
- Europe > Denmark > North Sea (0.70)
- (2 more...)
- Geology > Geological Subdiscipline > Geochemistry (0.86)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Mineral > Carbonate Mineral > Calcite (0.68)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Tor Formation (0.98)
- (10 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Novel Ways of Optimizing Production of Gas Wells Suffering from Downhole Salt Deposition
Janzen, M. R. (TotalEnergies Exploratie & Productie Nederland B.V., Den Haag, Netherlands) | Hornstra, E. (TotalEnergies SA, Pau, France) | Doldersum, B. (TotalEnergies Exploratie & Productie Nederland B.V., Den Haag, Netherlands)
Abstract Downhole salt precipitation is an increasing problem in the mature gas fields of the North Sea. With depletion and relatively high drawdowns, excessive evaporation of production water leads to salinities exceeding the solubility limits and thus salt deposition. This leads to significant losses of production and reserves, and increased costs as wells are traditionally shut-in, waterwashed regularly and/or choked back heavily. Two novel solutions have been conceptualized and applied, the first being installation of velocity strings. Besides increasing gas velocities to eliminate liquid loading, a smaller tubing has a downhole choking effect and as such strongly increases flowing pressures. A case study is presented wherein four velocity strings were set, leading to a strong increase in platform flowrate and extension of asset life. The major advantage of this solution is that it is relatively simple, extremely robust and does not involve any increased OPEX. As it involves increased flowing pressures, it is best applied to lower quality producers. Due to their steep inflow performance relation, there is only a very limited decrease in flowrate upon installation of the smaller tubing. For good to excellent quality reservoirs, the choking effect by a velocity string causes a flowrate decrease of often 40 to 50% - too significant to yield attractive economics. As such, it is a better option to compensate for the evaporation rate by external supply of fresh water. Proof of concept has been delivered for 1) using recycled low salinity/oxygen process water for water washing and 2) continuous downhole fresh-water injection by a successful three-week pilot test. During the latter, injection rates of approximately 1 m/d have been achieved, which is shown to effectively eliminate downhole salt deposition for the presented case.
Reactive Transport Modelling for a More Rigorous Scaling Risk Evaluation and Mitigation in a Giant U.A.E Carbonate Field
Baraka-Lokmane, S. (TotalEnergies) | Wang, X. (Parex Solutions) | Bigno, Y. (ADNOC) | Decroux, B. (TotalEnergies) | Olsen, J. (TotalEnergies) | El Hassan, M. (ADNOC) | Younes, D. (ADNOC) | Singleton, M. (Heriot-Watt University) | Mackay, E. (Heriot-Watt University)
Abstract After years of peripheral water injection with no significant scaling issues, pattern water injection and water injection at the GOC (Inner Ring Water Injection, or IRWI) are planned to be implemented in various reservoirs of this giant field. In a few pilot pairs, seawater injection is already taking place at a smaller spacing than historically applied. This allows testing of the injection schemes and assessment of the effect of heterogeneities before deploying pattern water injection and IRWI in the longer term. In this context, the scaling risk at the producer has been evaluated. The scaling risk assessment carried out with a thermodynamic prediction model has shown both SrSO4 and CaSO4 risks due to the mixing of formation water with injected seawater. This modelling fails to take account of geochemical reactions occurring in the reservoir; consequently, the scaling risk is usually overestimated. In this work, a reactive transport reservoir modelling tool has been used to investigate the impact of injection water composition on the scaling risk at the producer. In this model, the following are incorporated: aqueous component transport, partitioning of CO2 between aqueous and hydrocarbon phases, aqueous speciation reactions, mineral precipitation/dissolution reactions and heat transport. The simulations have considered full and reduced sulfate seawater injection with and without the presence of a thief zone. When full seawater is injected, the producer faces a risk of CaSO4 and no risk of SrSO4. This is the consequence of various coupled in situ mineral reactions, including dissolution and precipitation of carbonates and sulfates, which depend on propagation of temperature and CO2 desaturation fronts, as well as the other aqueous components. With the presence of a thief zone, SrSO4 presents a small scaling risk soon after seawater breakthrough; CaSO4 deposition has an initial peak soon after SrSO4 scaling. When reduced sulfate seawater is injected with and without the presence of the thief zone, there is no scaling risk for either SrSO4 or CaSO4. The results obtained by the reactive transport modelling tool match the general trends of scale deposition observed in the pattern injection well pair pilot to date. In this pilot a thief zone was identified in the vicinity of the injector and has contributed to accelerated water breakthrough at the producer. A peak in SrSO4 scale was observed in the early phase of water production, in agreement with the modelling results. A geochemical transport reservoir model was able to provide a full picture of seawater breakthrough at the production well, considering the impact of the thief zone. The required level of sulfate in the injected seawater, to prevent sulfate scales at the producer, has been determined. These results will help determine the scale mitigation strategy for the future development of this field.
- Europe (0.68)
- Asia > Middle East > UAE > Sharjah Emirate (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.16)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Mineral > Sulfate (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/17 > Tiffany Field (0.99)
- Asia > Middle East > UAE > Sharjah > Oman Mountains Foldbelt Basin > Sajaa Field > Thamama Group Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Ghasha Concession > Umm Shaif and Nasr Block > Umm Shaif and Nasr Field > Umm Shaif Field > Thamama Group Formation (0.99)
- (2 more...)
While formation damage is typically a problem affecting the productivity of well, it can also pose problems for injection. Understanding the causes of this type of formation damage is important so that efforts to prevent it can be undertaken. This page discusses the types of formation damage that affect injection wells. In such projects, the cost of piping and pumping the water is determined primarily by reservoir depth and the source of the water. However,water treatment costs can vary substantially, depending on the water quality required.
- Europe (1.00)
- North America > United States > Louisiana (0.29)
- North America > United States > Alaska (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.36)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Europe > Germany > Molasse Basin (0.99)
- Well Drilling > Formation Damage (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Abstract This paper uses reactive transport modelling to analyse the impact of variations in the water and gas injection flow rates from a geochemical perspective on the scaling potential of carbonate reservoirs under CO2-WAG injection. A sensitivity analysis of the calcite saturation index is performed for different water and gas injection flow rates. Geochemical properties of the injection fronts are analysed through the reservoir. The study is carried out using a 1D model of water-alternating-gas injection, assuming a light oil with 1.2% CO2 concentration, desulphated seawater injection and calcite as the rock substrate. The reactive transport modelling is performed using a commercial compositional reservoir simulator with the WOLERY database. Pressure, temperature, formation water (FW) and injected water (IW) compositions are based on published data. The scale potential is measured by calculating the saturation index and water production rates. Results show that calcite dissolution occurs continuously in the block closest to the injection well, and equilibrium is not reached in this region during water injection, but it is reached during CO2 injection. The extent of the reaction decreases from the injector to the producer well because the fluid becomes more saturated with CO2 as it flows through the reservoir. The reaction also decreases as the water and gas injection flow rates decrease, mainly due to the reduced volume throughput. The reactions during the water injection part of the cycle occur further away from the waterflood front as the water injection rate declines, and the reactions during the CO2 injection part of the cycle occur further away from the gas flood front as the CO2 injection rate declines. The system takes longer to reach equilibrium at lower flow rates, and so the water composition varies for longer. In the highest water flow rate model, it takes a very short time to reach equilibrium after the water breakthrough in the producer well. In the lowest water flow rate model, it takes more than five times as long. This work indicates the previously unreported finding that the water and gas injection flow rates may affect the geochemical equilibrium in the reservoir, specifically demonstrating that the reactions during the non-equilibrium stage may occur further away from the water and gas flood fronts, depending on the water and gas flow rates.
- South America > Brazil (0.93)
- North America > United States (0.68)
- Asia > Middle East > UAE (0.28)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.72)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.98)
- 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 > Chemical flooding methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract This paper discusses the efficiency of design, application, and pumping schedule of organic acid treatments used for mature fields in Iraq. Due to challenging completion schematics, an enhanced fluid placement method consisting of coiled tubing (CT), nitrogen, and a fluidic oscillator tool (or combination) is presented. By the time a well completion is achieved, oil production for most wells begins to decrease because of formation damage caused by fines migration, clay swelling, scale deposition, emulsions, organic deposits, or previous unsuccessful hydrochloric acid (HCl) or HCl/hydrofluoric acid (HF) stimulation treatments. A matrix stimulation/acidization using a tool that enables pumping the treatment, either as near as possible to or reciprocating across the perforations, is necessary to help remove formation damage, enhance recovery, and increase oil production (producer wells) or water injection (injector wells). Matrix stimulation treatments were performed for both producer and injector wells for an Iraq field, demonstrating enhanced conductivity results and increasing oil production up to 2000 BOPD over the last production rate or improving the water injectivity rate by 10000 BWPD. In addition, for those wells in which an electrical submersible pump (ESP) was installed, it was necessary that the selected stimulation fluids did not adversely affect the internal components of the ESP. To reach this goal, analysis of the following parameters was performed: mineralogy, regain permeability test, temperature, fluids properties, rock properties, and formation damage. Based on the analysis, customized designs assisted by software simulations were developed to determine the most effective treatment selection. Novel/Additive Information (25-75 words suggested) This paper describes how well information and correct analysis, and design can help to develop a customized optimal intervention strategy, identify the best solution to remove the formation damage, and deliver value added to the operators.
- North America > United States (1.00)
- Asia > Middle East > Iraq (0.81)
- Geology > Geological Subdiscipline (0.87)
- Geology > Mineral > Silicate > Phyllosilicate (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- South America > Ecuador > Orellana > Oriente Basin > Sacha Field (0.99)
- South America > Colombia > Putumayo Department > Putumayo Basin (0.99)
- Well Drilling > Formation Damage (1.00)
- Well Completion > Acidizing (1.00)
- Production and Well Operations > Well Intervention (1.00)
- (4 more...)
First Application in Oman of New Single Stage Retarded Sandstone Matrix Acidizing
Qassabi, Hajir (Petroleum Development of Oman) | Rafliansyah, Andika Putra (Petroleum Development of Oman) | Falla, Johnny (Petroleum Development of Oman) | Al-Yaaribi, Ahmed (Petroleum Development of Oman) | Al-Ruzeiqi, Saleh (Baker Hughes)
Abstract The objective of matrix acidizing in sandstone reservoirs using acid systems that contains Hydrofluoric acid (HF) is to widen the pore throats and spaces in order to increase the permeability around the wellbore and remove formation damage. One major disadvantage of this acid system is the secondary and tertiary reactions, which may lead to precipitations that damage the formation. Because of this, pumping sufficient pre-flush and post-flush volumes of Hydrochloric acid (HCl) is critical to prevent such damaging reactions. However, the placement of such fluids still is a concern in multiple opened layers or long open intervals zones. Stimulating sandstone reservoirs in the Southern fields of the Sultanate of Oman is very challenging, especially in those that exhibit relatively low permeability. These formations, based on petrology work, contains significant amounts of clays and feldspars, which make it difficult in the designing process of the acid formulation. A new version of HF acid system was recently developed. It is specially formulated, so it does not require the addition of Hydrochloric acid (HCl) pre-flush. Because of this, it can be pumped as a Single Stage Retarded Acid System. In addition, its higher reactivity allows deeper penetration, and it has the ability to minimize secondary reactions and damaging precipitates. Lab testing work was conducted to ensure the effectiveness of this Single Stage Retarded Acid System. The results were promising as they show a good improvement in the rock permeability. These results were encouraging to carry field trials in the sandstone reservoirs in Oman Southern fields. Up to now, it has been pumped in sandstones for oil producer wells and for water injector wells. The actual treatment using this system showed increased oil productivity by higher than 60% as well it shows higher than 80% in water injectivity. This paper presents the testing, designing and pumping the SSRAS (Single Stage Retarded Acid System), as well as the comparison with the conventional HF acid system in Southern fields of Oman. It outlines the laboratory work and analysis done as well as the field trials.
- Asia > Middle East > Oman (1.00)
- Africa > Middle East > Algeria > Tamanrasset Province (0.65)
- Africa > Middle East > Algeria > Adrar Province (0.65)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract To face the worldwide shortage of fresh water resources and the increase demand of oil and gas, researchers have devoted to study on application of seawater as a base fluid for hydraulic fracturing. One of the primary challenges for seawater fracturing application is the scale precipitation tendency due to the incompatibility of high sulfate concentration with high calcium, barium or strontium concentration in formation water, which will lead to overall reduction in production capacity. This work aims to develop a chemical precipitation method, which is a low cost way to remove sulfate before injection to solve the scale problem. Barium chloride dihydrate was used to precipitate sulfate from seawater for hydraulic fracturing. The chemical dosage, working temperature and precipitation time were optimized. The sulfate concentration in treated water was determined using an inductively coupled plasma mass spectrometer (ICP-MS). The sedimentation speed to separate treated water and precipitates at different precipitation time was measured using an optical particle stability analyzer. The obtained precipitates were dried at 60?C, and the morphology was observed using scanning electron microscopy (SEM) and X-ray diffraction method (XRD). Experimental results showed the barium chloride dihydrate can reduce the sulfate concentration in seawater from more than 4,000 ppm to less than 200 ppm when the dosage barium is higher than 5,500 ppm. The reaction efficiency is not altered in the temperature range from 15ยบC to 45ยบC. It turned out the treated seawater could meet the requirement for hydraulic fracturing application. As to the separation of water and precipitates using sedimentation method, it showed the highest speed appeared when precipitation time was 5 mins. And the addition of flocculants cannot improve the sedimentation speed. In addition, SEM results showed the size of obtained precipitates was in nanometer range. Besides, XRD confirmed the composition of precipitates were barium sulfate with purity >90%. The characterization results demonstrated the precipitates could be used as additives in drilling fluid, which will greatly reduce the operation cost. The work has revealed that barium sulfate precipitation method is promising to remove sulfate in seawater for hydraulic fracturing. Besides, the obtained barium sulfate is a commercially valuable product used in drilling fluid. Comparing to nanofiltration methods, this method is low cost and has no energy input requirement, which is suitable for a low carbon economy.
- North America > United States (0.68)
- Asia > Middle East > Saudi Arabia (0.47)
- Well Completion > Hydraulic Fracturing (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.87)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.68)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (0.66)
Successful Testing of ASP Flooding Without Water Softening in the Marmul Field in Southern Oman
Al Farsi, Samya (Petroleum Development Oman) | Bouwmeester, Ron (Shell Global Solutions International BV) | Al Bulushi, Abdullah (Petroleum Development Oman) | Karpan, Volodimir (Shell Development Oman LLC) | Al Mahruqi, Dawood (Petroleum Development Oman) | Al Sulaimani, Hanaa (Petroleum Development Oman)
Abstract Alkaline Surfactant Polymer (ASP) flooding has proven to be an effective method to recover remaining oil after a water flood through numerous laboratory and field tests. Yet, several operational complications limit the broad implementation of ASP technology. Source water requires softening to avoid injectivity issues due to scale formation when alkali is added to the solution. Even when softened water is used to prepare the injected ASP solution, scaling is often an issue in producing wells due to the mixing of injected ASP solution and harder reservoir brine in situ. Scale control through scale inhibitors has been reported to be successful in some cases. Usually, sodium carbonate is used as an alkali in ASP, and carbonate scaling issues are most severe in such a case. However, even if another alkali is used, carbonate scale remains an issue because, at high pH, the bicarbonate present in almost any formation water will be converted to carbonate and subsequently precipitate with the divalent ions present in the formation brine or unsoftened ASP make-up water. Monoethanolamine (MEA) has been used as an alkali in the ASP Phase 1A project in a sandstone reservoir in Southern Oman. The produced water reinjected in the field has a relatively low concentration of divalent ions. It was realized that further ASP implementation could be significantly simplified if softening of the produced water could be avoided. Based on the results of extensive laboratory studies, it was proposed to conduct the scaling inhibitor injection and propagation field trial. The trial's objective is to evaluate the use of a suitable scale inhibitor with the MEA-based ASP formulation as an alternative to water softening under field conditions. This project was executed after completing ASP Phase 1A and lasted about two months. Injection and production results from the trial and implications for future ASP implementation are presented in the paper.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.46)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.57)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)