High Temperature Sandstone Reservoirs Research Articles

Evaluation of a Novel Recrosslinkable Hyperbranched Preformed Particle Gel for the Conformance Control of High-Temperature Reservoirs with Fractures

Summary The existence of high conductivity features such as fractures, karst zones, and void space conduits can severely restrict the sweep efficiency of waterflooding or polymer flooding. Preformed particle gel (PPG), as a cost-effective technology, has been applied to control excessive water production. However, conventional PPG has limited plugging efficiency in high-temperature reservoirs with large fractures or void space conduits. After water breakthrough, gel particles can easily be washed out from the fractures because of the lack of particle-particle association and particle-rock adhesion. This paper presents a comprehensive laboratory evaluation of a novel water-swellable high-temperature resistant hyperbranched recrosslinkable PPG (HT-BRPPG) designed for North Sea high-temperature sandstone reservoirs (130°C), which can recrosslink to form a rubber-like bulk gel to plug such high conductivity features. This paper systematically evaluated the swelling kinetics, long-term thermal stability, and plugging performance of the HT-BRPPG. Bottle tests were used to test the swelling kinetic and recrosslinking behavior. High-pressure-resistant glass tubes were used to test the long-term thermal stability of the HT-BRPPG at different temperatures, and the testing lasted for more than 1 year. The plugging efficiency was evaluated by using a fractured model. Results showed that this novel HT-BRPPG could recrosslink and form a rubber-like bulky gel with temperature ranges from 80 to 130°C. The elastic modulus of the recrosslinked gel can reach up to 830 Pa with a swelling ratio (SR) of 10. In addition, the HT-BRPPG with an SR of 10 has been stable for over 15 months at 130°C. The core flooding test proved that the HT-BRPPG could efficiently plug the open fractures, and the breakthrough pressure is 388 psi/ft. Therefore, this novel HT-BRPPG could provide a solution to improve the conformance of high-temperature reservoirs with large fractures or void space conduits.

In-depth experimental investigations of low-tension gas technique with methane and live oil in high salinity and high temperature sandstone reservoirs

Low-Tension gas (LTG), as an emerging technique, attempts to synergize oil desaturation by microemulsion and mobility control via foam, which is an ideal alternative wherever other tertiary recovery techniques are technically limited. Previously, high oil recovery was achieved with proposed formula and novel injection strategy under harsh conditions (190,000 ppm, 85 °C) [53] with N2 and dead oil, which were robust to wide reservoir scenes (0.5 ft/d, 7 md) [54]. Here, more practical field scenarios are examined with methane and live oil for the first time facilitated by auxiliary tests of bulk foam stability, microemulsion viscosities and surfactant retention. Microemulsion phase behaviors are probed for both N2 and CH4 under reservoir pressure (1200 psi, 85 °C) in sequence to distinguish the impacts of pressure and solution gas. Therewith, pressure drop, effluent salinity and oil recovery are recorded to analyze effects of mobility control, gas type (N2 or CH4) and oil condition (dead or live) through multiple corefloodings stepwise. It is found higher pressure and solubilized methane impose limited impacts on current microemulsion phase behaviors. The developed formula and novel injection strategy satisfy the requirements of mobility control and oil desaturation, through the balance between foam stability and relatively low IFT. The surfactant retention is 0.162 mg/g during LTG process. Neither gas type or oil condition exerts discernible influences indicated by similarly high oil recoveries around 90%. The findings here promote the field implementation of this novel technique for both greenhouse gas utilization and enhanced oil recovery.

New insights into guar gum as environmentally friendly polymer for enhanced oil recovery in high-salinity and high-temperature sandstone reservoirs

Chemical enhanced oil recovery (EOR) processes are usually used as additives for hydrocarbon production due to its simplicity and relatively reasonable additional production costs. Polymer flooding uses polymer solutions to increase oil recovery by decreasing the water/oil mobility ratio by increasing the viscosity of the displacing water. The commonly used synthetic water-soluble polymer in EOR application is partially hydrolyzed polyacrylamide (HPAM). However, synthetic polymers in general are not attractive because of high cost, environmental concerns, limitation in high temperature, and high-salinity environment. Guar gum is an environmentally friendly natural water-soluble polymer available in large quantities in many countries and widely used in various applications in the oil and gas industry especially in drilling fluids and hydraulic fracturing operations; however, very limited studies investigated on guar as a polymer for EOR and no any study investigated on its uses in high-temperature and high -salinity reservoirs. The objective of this study is to confirm the use of guar gum as a natural polymer for EOR applications in sandstone reservoirs and investigate its applicability for high-temperature and high-salinity reservoirs. The study experimentally investigated rheological characteristics of a natural polymer obtained from guar gum with consideration of high temperature (up to 210 °F) and high salinity (up to 20% NaCl) and tested the guar solution as EOR polymer. The results of this study show that the guar solution can be used as an environmentally friendly polymer to enhance oil recovery. Based on the results, it can be concluded that guar gum shows shear-thinning behavior and strongly susceptible to microbial degradation but also shows a very good properties stability in high temperature and salinity, where in low shear rate case, about 100 cp viscosity can be achieved at 210 °F for polymer prepared in deionized water. Guar polymer shows good viscosity in the presence of 20% NaCl where the viscosity is acceptable for temperature less than 190 °F. Also, the flooding experiment shows that the recovery factor can be increased by 16%.

Numerical investigation of optimum ions concentration in low salinity waterflooding

Injecting low saline water is one of the practices used to improve hydrocarbon production that has recently significantly grown due to its advantages over seawater and chemical flooding. Although many theories and mechanisms have been provided on how additional oil recovery has been achieved utilizing low salinity waterflooding, the principle fundamentals of the mechanism(s) are still ambiguous. This article investigates the potential use of low salinity waterflooding (LSWF) to improve oil production from a sandstone formation. A 3D field-scale model was developed using Computer Modeling Group ( generalized equation-of-state model simulator) based on a mature oil field data. The developed model was validated against actual field data where only 8% deviation was observed. Simulation analysis indicated that multi-component ion exchange is a key factor to improve oil production because it alters rock wettability from oil-wet to water-wet. Simulation sensitivity studies showed that low salinity water flooding provided higher oil production than high water salinity flooding. Moreover, simulation showed early breakthrough time of low salinity water injection can provide high oil recovery up to 71%. Therefore, implementing LSWF instantly after first stage production provides recovery gains up to 75%. The determined optimal injected brine composition concentration for Ca 2+ , Mg 2+ and Na + are 450, 221, and 60 ppm, respectively. During LSWF, a high divalent cations and low monovalent cations’ concentration can be recommended for injected brine and formation aquifer for beneficial wettability alteration. Simulation also showed that reservoir temperature influenced the alteration of ion exchange wettability during LSWF as oil recovery increased with temperature. Therefore, high temperature sandstone reservoirs can be considered as a good candidate for LSWF. Cited as : Ben Mahmud, H., Mahmud, W.M., Arumugam, S. Numerical investigation of optimum lons concentration in low salinity waterflooding. Advances in Geo-Energy Research, 2020, 4(3): 271-285, doi: 10.46690/ager.2020.03.05

A Numerical Investigation of Low-Salinity Waterflooding Capability to Enhanced Oil Recovery

Low-salinity water flooding (LSWF) is one of techniques that can be used to improve oil production and has gained a significant attention in these days because of its advantages over conventional water flooding and chemical flooding. Even though many mechanisms have been recommended on an extra oil recovery achieved using LSWF process, the principle fundamental of the mechanism is still not fully understood. This research paper investigates the potential of oil recovery in an onshore sandstone reservoir using LSWF. A field-scale three–dimensional reservoir model has been developed via CMG’s GEM compositional simulator where the model validated against a real production field data that were in good agreement with a deviation value of 8%. The primary mechanism of LSWF has been identified by providing incremental oil recovery due to a multi-component ion exchange mechanism that causes wettability alteration of reservoir rock from oil-wet to water-wet. The sensitivity study showed that LSWF provides a higher accumulative oil production compared to conventional high salinity water injection with 13.5 and 12 MMSTB. Moreover, the early time of low saline brine injection can provide a maximum oil recovery up to 71%. Therefore, implementing this scenario immediately after the primary recovery, it provides production benefits in both secondary and tertiary method. The oil recover factor increased to 75.5% with the increasing of brine injection rate up to an optimum value of 5320 bbl/d. A reservoir temperature also influenced the ion exchange wettability alteration during LSWF in which as the temperature increasing enhances the oil recovery. Therefore, a high temperature sandstone reservoir will be a potential candidate for LSWF.

Smart Water injection strategies for optimized EOR in a high temperature offshore oil reservoir

Smart Water injection is an EOR technique that is both environmentally friendly and easily implementable to a fractional cost compared to other water-based EOR methods. EOR by Smart Water is a wettability alteration process towards more water-wet conditions, which induces increased positive capillary forces and increased microscopic sweep efficiency.The objective of this work was to evaluate the injection strategy for Smart Water in an offshore high temperature sandstone reservoir, and compare the efficiency of seawater-based injection brines with low salinity brines, which can behave as Smart Water in sandstone reservoirs. Oil recovery experiments have been performed at reservoir conditions using preserved reservoir cores and reservoir fluids.Secondary low salinity injection gave an average of 33.5 %OOIP extra oil produced, compared to modified seawater injection. The tertiary low salinity EOR effect after modified seawater flooding gave an average of 11.8 %OOIP extra oil. Significant changes in produced water pH from initially acidic to alkaline conditions during low salinity injection were observed, favoring wettability alteration towards more water-wet conditions.The results confirmed that low salinity brine behaved as a Smart Water, contributing with significant extra oil recovery in a high temperature sandstone reservoir. Introducing Smart Water from day one in a reservoir, i.e. in secondary recovery mode, is significantly more efficient, regarding both response time and ultimate oil recovery, than tertiary mode Smart Water injection.

Impact of temperature on the low salinity EOR effect for sandstone cores containing reactive plagioclase

Previous experimental work has indicated that the induced increase in pH as the high salinity formation brine is displaced by low salinity brine, is a key factor for observing low salinity EOR effects. The pH gradient is mainly due to desorption of Ca2+ from the clay surface in the presence of low salinity brine depleted in Ca2+. Desorption of Ca2+ from the clay surface is an exothermic process, which decreases the pH gradient as the temperature is increased. Therefore, a decrease in the low salinity EOR effect at high temperatures is observed. Some types of reactive plagioclase, especially albite, may also influence the pH as the brine salinity is changed. The exchange of Na+ with H+ is less temperature sensitive.Tertiary low salinity EOR effects from outcrop core material containing both clay, ≈10 wt%, and reactive albite, ≈30 wt%, have been studied at 60 and 120 °C. The low salinity EOR effects at the two temperatures were quite similar, 9.2 and 8.7% of OOIP, respectively. The oil recovery test results agreed well with the observed pH gradients for the oil-free core material, which were also quite similar, 2.3 and 2.2 pH units at 60 and 120 °C. The oil recovery and pH screening results showed that ion exchange at the albite surface will partly compensate for the decreased ion exchange at the clay surface at higher temperatures. Therefore, the presence of reactive plagioclase in high temperature sandstone reservoirs seems to be favorable for observing LS EOR effects provided the initial pH of formation water is low enough to make the rock mixed wet.

Mixtures of Anionic/Cationic Surfactants: A New Approach for Enhanced Oil Recovery in Low-Salinity, High-Temperature Sandstone Reservoir

Summary Test results indicate that a lipophilic surfactant can be designed by mixing both hydrophilic anionic and cationic surfactants, which broaden the design of novel surfactant methodology and application scope for conventional chemical enhanced-oil-recovery (EOR) methods. These mixtures produced ultralow critical micelle concentrations (CMCs), ultralow interfacial tension (IFT), and high oil solubilization that promote high tertiary oil recovery. Mixtures of anionic and cationic surfactants with molar excess of anionic surfactant for EOR applications in sandstone reservoirs are described in this study. Physical chemistry properties, such as surface tension, CMC, surface excess, and area per molecule of individual surfactants and their mixtures, were measured by the Wilhelmy (1863) plate method. Morphologies of surfactant solutions, both surfactant/polymer (SP) and alkaline/surfactant/polymer (ASP), were studied by cryogenic-transmission electron microscopy (Cryo-TEM). Phase behaviors were recorded by visual inspection including crossed polarizers at different surfactant concentrations and different temperatures. IFTs between normal octane, crude oil, and surfactant solution were measured by the spinning-drop-tensiometer method. Properties of IFT, viscosity, and thermal stability of surfactant, SP, and ASP solutions were also tested. Static adsorption on sandstone was measured at reservoir temperature. IFT was measured before and after multiple contact adsorptions to recognize the influence of adsorption on interfacial properties. Forced displacements were conducted by flooding with water, SP, and ASP. The coreflooding experiments were conducted with synthetic brine with approximately 5,000 ppm of total dissolved solids (TDS), and with a crude oil from a Sinopec reservoir.

Influence of Formation Water Salinity/Composition on the Low-Salinity Enhanced Oil Recovery Effect in High-Temperature Sandstone Reservoirs

The mechanism of the low-salinity (LS) enhanced oil recovery (EOR) process in sandstone reservoirs has been debated in the literature for more than a decade. We recently proposed a chemical wettability alteration mechanism for the process, well-founded in experimental observations. Even though the chemical understanding is quite well-described, there are parameters/factors that could influence the main process. Combinations of certain reservoir minerals, temperature, and salinity/composition of the formation water (FW) could have impact on the EOR process by affecting: (1) the initial wetting condition and (2) the wettability alteration process when the high-salinity (HS) FW is displaced by LS water. It has been experimentally observed that the LS EOR effect decreases as the reservoir temperature increases. This paper discusses the LS EOR effect related to oil recovery at high temperatures, Tres > 100 °C, and high FW salinities, ∼200 000 ppm. In general, the adsorption of active organic polar components o...

A New Multichelating Acid System for High-Temperature Sandstone Reservoirs

Sandstone reservoir acidizing is a complex and heterogeneous acid-rock reaction process. If improper acid treatment is implemented, further damage can be induced instead of removing the initial plug, particularly in high-temperature sandstone reservoirs. An efficient acid system is the key to successful acid treatment. High-temperature sandstone treatment with conventional mud acid system faces problems including high acid-rock reaction rate, short acid effective distance, susceptibility to secondary damage, and serious corrosion to pipelines. In this paper, a new multichelating acid system has been developed to overcome these shortcomings. The acid system is composed of ternary weak acid, organic phosphonic chelating agent, anionic polycarboxylic acid chelating dispersant, fluoride, and other assisted additives. Hydrogen ion slowly released by multistage ionization in ternary weak acid and organic phosphonic within the system decreases the concentration of HF to achieve retardation. Chelating agent and chelating dispersant within the system inhibited anodic and cathodic reaction, respectively, to protect the metal from corrosion, while chelating dispersant has great chelating ability on iron ions, restricting the depolarization reaction of ferric ion and metal. The synergic effect of chelating agent and chelating dispersant removes sulfate scale precipitation and inhibits or decreases potential precipitation such as CaF2, silica gel, and fluosilicate. Mechanisms of retardation, corrosion-inhibition, and scale-removing features have been discussed and evaluated with laboratory tests. Test results indicate that this novel acid system has good overall performance, addressing the technical problems and improving the acidizing effect as well for high-temperature sandstone.

Characterisation of culture-independent and -dependent microbial communities in a high-temperature offshore chalk petroleum reservoir

Recent studies have indicated that oil reservoirs harbour diverse microbial communities. Culture-dependent and culture-independent methods were used to evaluate the microbial diversity in produced water samples of the Ekofisk oil field, a high temperature, and fractured chalk reservoir in the North Sea. DGGE analyses of 16S rRNA gene fragments were used to assess the microbial diversity of both archaeal and bacterial communities in produced water samples and enrichment cultures from 4 different wells (B-08, X-08, X-18 and X-25). Low diversity communities were found when 16S rDNA libraries of bacterial and archaeal assemblages were generated from total community DNA obtained from produced water samples and enrichment cultures. Sequence analysis of the clones indicated close matches to microbes associated with high-temperature oil reservoirs or other similar environments. Sequences were found to be similar to members of the genera Thermotoga, Caminicella, Thermoanaerobacter, Archaeoglobus, Thermococcus, and Methanobulbus. Enrichment cultures obtained from the produced water samples were dominated by sheathed rods. Sequence analyses of the cultures indicated predominance of the genera Petrotoga, Arcobacter, Archaeoglobus and Thermococcus. The communities of both produced water and enrichment cultures appeared to be dominated by thermophilic fermenters capable of reducing sulphur compounds. These results suggest that the biochemical processes in the Ekofisk chalk reservoir are similar to those observed in high-temperature sandstone reservoirs.

Acid Stimulation of High-Temperature Sandstones in Eastern Venezuela

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 98318, "Effective Stimulation of High-Temperature Sandstone Formations in East Venezuela With a New Sandstone-Acidizing System," by S.A. Ali, SPE, and C.W. Pardo, SPE, Chevron Energy Technology Co., and Z. Xiao, SPE, F.E. Tuedor, SPE, A. Boucher, SPE, S.A. Al-Harthy, B. Lecerf, and G. Salamat, SPE, Schlumberger, prepared for the 2006 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 15–17 February. Wells in this eastern Venezuela oil field have a bottomhole temperature of approximately 230°F and varied mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate-scale damage have been reported. A novel chemical system was developed to stimulate these high-temperature sandstone reservoirs. Introduction Most of the wells in this field in Maracaibo, Venezuela, have several perforated intervals covering up to 1,000 ft, with a net perforated interval of up to 500 ft. The mineralogy varies from interval to interval, with 4 to 16% calcium carbonate (CaCO3), 6 to 18% clays (mainly kaolinite), 5 to 10% feldspars, and 2 to 5% siderites in some wells. Reservoir pressures range from 800 to 2,500 psi, and skin values vary across the zones. Permeability varies from 1 to 200 md among the zones. The main formation-damage mechanisms were identified as fines migration (80 to 90% production decline after treatment) and CaCO3 scales, mainly from loss of workover fluids. Various formulations of mud acid, organic-clay acid, and solvents are used to treat these wells, with mixed results. The new sandstone-acidizing system was developed to treat multilayered high-temperature (200 to 375°F) reservoirs with long production intervals and complex mineralogy. The new sandstone-acidizing fluid uses a single-stage placement process, has less precipitation tendency and reduced tubular and production-equipment corrosion, and reduces exposure of hazardous fluids to wellsite personnel and the environment. A comprehensive laboratory study, which included acid-solubility tests, X-ray diffraction (XRD) analysis, batch reaction kinetics, fines-migration tests, and core-flow tests, was conducted on field cores to evaluate the performance of this sandstone-acidizing system and compare it with currently used systems. Experiment Twelve core plugs were used from the formation sand in the oil field. Six plugs were from the 7,951- to 7,953-ft interval, five from the 7,723- to 7,727-ft interval, and one from the 7,757- to 7,758-ft interval. All samples were 1 in. in diameter and approximately 2 to 3 in. long. These core samples were classified into groups of high- and low-permeability sands, although a slight difference in physical appearance was observed in the laboratory. Acid solubility tests were run on 10 samples. Mineralogical information is very important in sandstone-acidizing treatments. XRD was used to quantify the mineralogical composition of the core samples. Typical minerals in sandstone rock include silica (quartz), feldspars (plagioclase, K-feldspar), clays (kaolinite, illite, chlorite, smectite, and mixed-layered illite and smectite), zeolites, micas, carbonates (dolomite, calcite), sulfides, and sulfates (gypsum, anhydrite, and barite).

Numerical Simulation of CO2 Flood Performance

AbstractA multicomponent, three-phase, three-dimensional (3D) reservoir simulator has been developed for predicting miscible flood performance with particular emphasis on CO2 flooding. Several features, not all normally found represented in either a black-oil or compositional simulator, are represented in the simulator described here. These features include (1) heavy-end dropout and concomitant reduction in phase mobility, (2) water blocking of oil from an invading solvent, (3) viscous instability (fingering) at the CO2 displacement front, (4) miscible/immiscible transition as a function of pressure and composition, and (5) loss of CO2 to the aqueous phase.The solution scheme employs an implicit in pressure, explicit in saturation and composition time integration scheme (IMPES). This scheme allows for ready use of a second-order correct spatial discretization. We have found that for field applications, a numerical grid fine enough to represent waterflood performance accurately is usually sufficient for representing CO2-miscible-type processes as well. The program automatically employs a stabilized Runge-Kutta time discretization to alleviate the usual stability limitations imposed by the IMPES procedure. Up to 49 times the usual stable timestep size can be employed for seven times as much computing work. Work required to simulate a given time period when stability is limiting was improved overall by a factor of seven. To date, we have not encountered a pattern flood displacement simulation where the increased timestep size provided by the Runge-Kutta scheme has not been adequate to maintain stability for timesteps chosen so as to limit truncation error.The CO2 flood simulator described has been in application for 4 years. The simulator has been used for design of CO2 EOR projects and interpretation of CO2 injectivity tests in several low-temperature west Texas San Andres dolomite reservoirs as well as high-temperature sandstone reservoirs. In addition to CO2 applications, the simulator has been used for the design of liquefied petroleum gas/dry gas flooding processes and for examining the effect of injection gas composition on oil recovery performance for immiscible gas drives.