Coreflood Tests Research Articles

Experimental study of degradable preformed particle gel (DPPG) as temporary plugging agent for carbonate reservoir matrix acidizing to improve oil recovery

Preformed particle gel (PPG) is an effective technique for conformance improvement in petroleum reservoirs. It can selectively penetrate high-permeability channels to form effective plugging and divert the chasing injection fluid to low-permeability unswept oil zones. However, conventional PPG would be dehydrated under acidic conditions and could not be easily degraded, which will cause a certain amount of damage to the target formation. Therefore, this study proposed to introduce acid-resistant functional groups and a self-degradable cross-linking structure into the conventional PPG's compositions to develop a degradable PPG (DPPG). The influence mechanism of the chemical composition, swelling performance, and temporary plugging performance of DPPG was studied. Results show that the DPPG can swell up to 70 times its original size by absorbing water, and swollen DPPG can finally self-degrade to a water-like fluid in acid solution. After injecting of DPPG swelled by 20 times its original volume, the injection pressure could reach 1250 psi. Even during the chase acid treatment period, the average pressure was around 130 psi, which shows excellent plugging performance. Subsequent injection of acid would react with carbonate rocks around the plugging zones, increasing the swept volume. In addition, after acid treatments, the DPPG could be self-degraded into a dilute solution like water, so it has very little damage to the reservoir matrix. Therefore, the DPPG has good temporary plugging and acidizing steering performance in acidizing operations. The research in this article can provide the experimental basis and reference for expanding the further application of DPPG in petroleum reservoir stimulation. • Acid-resistant and self-degradable cross-linking structures were introduced to develop a degradable PPG. • The swelling and degradation performance can be adjusted by changing its component concentration. • Coreflooding test reveals that DPPG has a good acid diversion function. • DPPG can undergo self-degradation in a wide range of acidity.

Determining water-oil relative permeability and capillary pressure from steady-state coreflood tests

This study aims at the simultaneous determination of relative permeability and capillary pressure from steady-state corefloods. Besides using the measurements of pressure-drop across the core and average saturation under steady-state conditions, we use the transient data between the sequential steady states. The inverse algorithm is based on four type curves “stabilizsation period versus water-cut” revealed by asymptotic analysis of the transient solution near end-point saturations, and on the exponential shape of transition data histories observed by direct numerical runs. The transition measurements are approximated in the stabilisation periods by the type curves using non-linear least-square optimisation. The Corey parameters for relative permeability and capillary pressure are fitted for each interval of sequential water-cuts. The inverse solver is applied to three sets of steady-state tests in oil-wet cores, where saturation profiles during steady-state flows have been measured along with the transition data. Extensive sensitivity analysis of the inverse solutions with respect to the small perturbation of the measured data reveals the stability of obtained relative permeability and capillary pressure. The close agreement between the measured stabilised saturation profiles and those obtained by the matched-based modelling in three oil-wet cases validates the method developed.

Impact of a novel biosynthesized nanocomposite (SiO2@Montmorilant@Xanthan) on wettability shift and interfacial tension: Applications for enhanced oil recovery

Nanoparticles are used in various nano-energy applications such as wettability shift of hydrophobic surfaces to hydrophilic surfaces in oil-brine-mineral systems and interfacial tension (IFT) reduction for enhanced oil recovery. This is possible due to their small size (1–100 nm) and chemical and physical properties. Mechanistically, they can interact with a fluid in the pore space and provide favourable conditions for wettability shift, IFT and oil viscosity reduction, and thus improve oil recovery. However, literature is scarce in terms of providing comprehensive information about the behaviour of nanocomposites (NCs) and associated formulations.In this paper, we present biosynthesis, characterization, and application of a novel nanocomposite (SiO2@Montmorilant@Xanthan) which is used with various concentrations (100, 250, 500, 1000, 1500, and 2000 ppm) as dispersing agents in porous media. The NC was characterized using X-Ray Diffraction (XRD), Scanning Electron Microscopy (SEM), Thermogravimetric Analysis (TGA), Fourier Transform Infrared Spectroscopy (FTIR), and Energy Dispersive Spectroscopy (EDS). The effects of different concentrations of the nano-suspensions on zeta potential, pH, conductivity, IFT, and wettability are investigated. Core flooding tests were done on sandstone and carbonate reservoir rocks to measure the secondary and tertiary recovery potential by injecting seawater and optimum NC concentrations, respectively.Zeta potential and conductivity experiments demonstrated that 250 ppm NCs can optimally reduce the IFT from 36 mN/m to 15.42 mN/m (56% reduction). The similar optimum concentration has shifted the wettability of examined carbonate rocks from 150° to 33° leading to an 11.72% increase in tertiary oil recovery. Whereas, the optimum concentration of NCs for sandstone rocks was 1000 ppm; which, has optimally altered the wettability from 140° to 34°, and has increased the tertiary oil recovery by 15.79%. This reduction in IFT, the reversal of wettability, and an increase in tertiary oil recovery can improve significantly the design of effective enhanced oil recovery schemes for petroleum reservoirs.

Profile Control Using Fly Ash Three-Phase Foam Assisted by Microspheres with an Adhesive Coating

Foam-assisted steam flooding is a promising technique to alleviate gas channeling and enhance sweep efficiency in heterogeneous heavy-oil reservoirs. However, long-term foam stabilization remains problematic at high temperatures. Three-phase foam (TPF), containing dispersed solid particles, has been proposed to improve foam stability under harsh reservoir conditions. We fabricated a novel TPF system by adding ultrafine fly ash particles, as well as high-temperature resistant microspheres with an adhesive coating layer. This work aims at assessing the ability of the generated TPF in controlling steam channeling and enhancing oil recovery. Static and core flood tests were performed to evaluate foam strength and stability. Our results suggested a stronger foamability at a lower consolidation agent concentration, while a longer half-life period of foam and settling time of solid particles at a larger consolidation agent concentration were observed. Bubbles suspended independently in the liquid phase, with sizes varying from 10 to 100 μm, smaller than that of the conventional foam, suggesting a significant enhancement of foam dispersity and stability. The plugging rate was close to 90% when the temperature was as high as 300 °C, demonstrating a well-accepted plugging effect under high temperatures. A larger pore volume injection of TPF yielded a higher EOR in parallel cores, which substantiated the effectiveness of the three-phase foam system in sealing high-permeability channels.

Potential application of novel amphiphilic Janus-SiO2 nanoparticles stabilized O/W/O emulsion for enhanced oil recovery

The Janus nanoparticles stabilized Pickering emulsions showed great application potential in various fields, including enhanced oil recovery (EOR). In this study, the amphiphilic Janus-SiO2 nanoparticles (Janus-C12) are successfully synthesized by the Pickering emulsion method and characterized by Fourier transform infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA), ζ-potential and contact angle measurements. The phase inversion from oil-in-water (O/W), multiple oil-in-water-oil (O/W/O) emulsion, to water-in-oil (W/O) emulsions was observed with the delicate control for the modification degrees of Janus-C12. The possible emulsification mechanisms for various Janus-C12 stabilized emulsions were proposed. The multiple O/W/O emulsion stability in harsh conditions and the influence factors (nanoparticles concentration, water/oil volume ratio and NaCl concentration) were studied systematically. Moreover, the Janus-C12–79% stabilized multiple O/W/O Pickering emulsions exhibited excellent EOR performance (additional oil recovery of 27.2%) in core flooding tests, and the possible EOR mechanism was explored via microscopic visualization experiments.

Precipitation/dissolution and precipitants movement mechanisms effects on injectivity variations during diluted produced water re-injection into a layered reservoir - experimental investigation

ABSTRACT Permeability reduction is one of the significant problems in the water injection process. Several mechanisms may be involved in permeability reduction including scale formation, suspended particle invasion and fines migration. On the other hand, rock dissolution may also lead to permeability improvement of carbonate rocks. In this research, effect of rock lithology along with incompatibility of injection and formation brines, scale formation and plugging of pores by particles in the injection water for a layered reservoir were examined. Diluted formation brine (produced from desalination unit) was considered as injection water. Simulation of scale formation due to thermodynamic conditions and mixing of formation and injection brines were performed to investigate amount and types of scales. Simulation and jar tests showed that Scale precipitation decreased with increasing the mixing ratio of injection water to 75%. For core flooding tests, both carbonate and sandstone core samples from a layered candidate reservoir were selected for monitoring of formation damage and permeability variation due to incompatibility of fluids. SEM and EDX analysis were used for static and dynamic tests. Carbonate core sample showed sever damage and competition between scale precipitation and rock dissolution. Higher flow rates contribute to permeability enhancement of carbonate rocks by prevention of scale sedimentation (less scale formation) and acceleration of carbonate rock dissolution. As a pressure difference increasing of 60% was shown in the first stage of water injection process into the carbonate rock. Eventually, after increasing and decreasing the injection rate, the pressure difference decreased to 30 presences. Scale formation mechanism is dominant in sandstone rock samples and can be removed by backflow. As pressure difference decreased 27% in sandstone rock sample, which resulted in permeability decrease from 365 to 265 mD.

Surfactant-Aided Low-Salinity Waterflooding for Low-Temperature Carbonate Reservoirs

Summary Carbonate reservoirs tend to be oil-wet/mixed-wet and heterogeneous because of mineralogy and diagenesis. The objective of this study is to improve oil recovery in low-temperature dolomite reservoirs using low-salinity and surfactant-aided spontaneous imbibition. The low-salinity brine composition was optimized using ζ-potential measurements, contact-angle (CA) experiments, and a novel wettability-alteration measure. Significant wettability alteration was observed on dolomite rocks at a salinity of 2,500 ppm. We evaluated 37 surfactants by performing CA, interfacial-tension (IFT), and spontaneous-imbibition experiments. Three (quaternary ammonium) cationic and one (sulfonate) anionic surfactants showed significant wettability alteration and produced 43–63% of original oil in place (OOIP) by spontaneous imbibition. At a low temperature (35°C), oil recovery by low-salinity effect is small compared with that by wettability-altering surfactants. Coreflood tests were performed with a selected low-salinity cationic surfactant solution. A novel coreflood was proposed that modeled heterogeneity and dynamic imbibition into low-permeability regions. The results of the “heterogeneous” coreflood were consistent with that of spontaneous-imbibition tests. These experiments demonstrated that a combination of low-salinity brine and surfactants can make originally oil-wet dolomite rocks more water-wet and improve oil recovery from regions bypassed by waterflood at a low temperature of 35°C.

Study of a Novel Carboxylic Cellulose Nanofibrils‐Ethoxylated Phytosterol‐Alcohol Environmentally Friendly System on the Application in Enhanced Oil Recovery

AbstractBio‐polymers and bio‐surfactants have attracted increasing attention for their application in chemical enhanced oil recovery (EOR) due to the environmental concerns of synthetic chemical agents. Here, a ternary compound system consisted of carboxylic cellulose nanofibrils (CCNF), ethoxylated phytosterol (BPS), and n‐pentanol was constructed. The rheological property and interfacial activity of the compound system and the effects of each component at high temperature (80 °C) was investigated systematically. The ternary compound system exhibited excellent performance in thickening, IFT reduction (<10−2 mN m−1), emulsification, and better salt tolerance. CBP, the ternary system of CCNF (2000 mg L−1), BPS (2000 mg L−1), and n‐pentanol (5000 mg L−1), greatly enhanced the oil recovery (24.3%) in the core flooding tests by its high displacement efficiency and sweep enlargement, which was demonstrated directly in the visual micromodel flooding. As an eco‐friendly system with remarkable performance, the compound system of CBP shows great application potential in EOR.

Research on synthesis and salt thickening behavior of a binary copolymer amphiphilic polymer

Polymer flooding technology has become a common flooding technology in medium-high permeability reservoirs. With the gradual development of high salinity reservoirs, higher requirements for the salt resistance of polymers have been put forward. Herein, a novel binary copolymer amphiphilic polymer (PAMA) with salt thickening property was synthesized by free radical polymerization without soap. The synthetic parameters of polymer were optimized by using apparent viscosity as evaluation index which were as follows: the monomer molar ratio of AM:MALPS was 97:3, and the concentration of initiator and total monomer was 0.02% and 25% respectively, polymerization temperature of 45 °C, and the reaction time of 4.5 h. The PAMA was characterized by FT-IR and 1HNMR. Meanwhile, the salt thickening mechanism was analyzed combining with the apparent viscosity and microscopic structure. Finally, the injection performance of PAMA was explored with the core flooding experiment, and the feasibility of PAMA in high salinity reservoir was evaluated. The results showed that the increase of hydrodynamic radius and enhancement of hydrophobic association made PAMA had the property of salt thickening. The core flooding test also showed that PAMA had salt thickening behavior and anti-scouring capacity in porous medium in high salt reservoirs. The microscopic displacement experiments showed that PAMA could enhanced the oil recovery by displacing the “blind end” residual oil and the residual oil in pore intersection.

Enhancing tight oil recovery using CO2 huff and puff injection: An experimental study of the influencing factors

A series of core flooding tests were conducted using a specially-designed matrix–fracture model to assess the performance of CO2 huff and puff (‘huff-n-puff’) injection with respect to the enhanced oil recovery (EOR) of tight oil. Four key influencing factors were taken into consideration: number of huff-n-puff cycles, matrix permeability, matrix size, and gas type. The results imply that CO2 huff-n-puff injection is capable of effectively recovering tight matrix oil, and there is an optimal cycle regime for such huff-n-puff processes which depends on matrix permeability, matrix size, etc. As the permeability of the matrix is less than 30.0 md, the effectiveness of CO2 huff-n-puff is significantly weakened as the permeability decreases, indicating the great difficulty encountered when developing tight oil reservoirs. Above this value, such effect diminishes. As the matrix size increases, oil recovery using CO2 huff-n-puff decreases and the effect is more obvious when the permeability is low. But, in general, matrix size has a weaker effect on EOR than permeability. Natural gas is a promising albeit less effective alternative when CO2 is unavailable.

Experimental investigation of immiscible water-alternating-gas injection in ultra-high water-cut stage reservoir

Water-alternating-gas (WAG) injection is recommended as a means of improving gas mobility control. This paper describes a series of coreflood tests conducted to investigate the potential for continuous gas injection and WAG injection in ultra-high water-cut saline reservoirs. The mechanisms of immiscible water-alternating-nitrogen injection on residual oil distribution are analyzed, and pore-scale analysis is conducted. The effect of injection parameters on residual oil distribution and recovery efficiency is also evaluated. Coreflood results show that tertiary oil recovery efficiency is significantly higher using WAG injection than continuous gas injection during the ultra-high water-cut period. Pore-scale visualization illustrates the movement of gas through the waterflooded channels into the pore space previously occupied by water and residual oil, which then becomes trapped. Injected gas breaks the force balance of microscopic residual oil and reduces residual oil saturation. This mobilizes the displaced/collected residual oil into large waterfilled pores and blocks several water channels. WAG flooding can decrease free-gas saturation and increase trapped-gas saturation significantly, resulting in decreased relative permeabilities of gas and water. The experimental results indicate that appropriate WAG design parameters could enhance recovery by 15.62% when the injected pore volume of water and gas in the cycle is 0.3 PV at a gas/water injection ratio of 2:1. The results from this study will allow researchers and reservoir engineers to understand and implement immiscible WAG injection as an enhanced oil recovery method in ultra-high water-cut stage reservoirs. Cited as: Kong, D., Gao, Y., Sarma, H., Li, Y., Guo, H., Zhu, W. Experimental investigation of immiscible water-alternating-gas injection in ultra-high water-cut stage reservoir. Advances in Geo-Energy Research, 2021, 5(2): 139-152, doi: 10.46690/ager.2021.02.04

Comparative study on the effects of guar gum nanocomposite and guar gum polymer solutions on enhanced oil recovery

Guar gum is a polysaccharide that occurs naturally, and has useful properties in thickening and stabilizing. This makes it of interest in enhanced oil recovery, because of its ability to increase the sweep efficiency of the recovery process. Also, guar gum has an economical and reliable supply as well as flexible chemistry. Guar gum, however, cannot interact with oil-rock surface or the oil-water interface, thereby limiting its capacity to recover crude oil. Nanoparticles can, therefore, be mixed with guar gum to increase its recovery potential. Silicon oxide nanoparticles can be combined with a polymer to form a polymer nanocomposite, which can then be used to increase the overall efficiency of the crude oil recovery process. In this study, the viscosity profile of guar gum was investigated under different conditions of temperature and weight percentages. Four temperatures were investigated: 30, 50, 75, and 90°C. Six weight percentages were also investigated in the viscosity tests: 0.1, 0.2, 0.3, 0.4, 0.5, and 1. The oil recovery potential of guar gum and guar gum nanocomposite was also investigated at different weight percentages. Across the six weight percentages used in the viscosity study, it was observed that there was an average percentage loss in viscosity of 33 % as the temperature was increased from 30°C to 90°C at the highest shear rate of 1021 s-1. At 30°C, the viscosity of guar gum was seen to increase by close to 1000 % as weight percentage was increased from 0.1 to 1. The recovery factor observed during core flooding tests utilizing guar gum at three different concentrations indicated an increment of 48, 51, and 54% respectively. On addition of silicon oxide nanoparticles at different concentrations, oil recovery was enhanced by 54 % to 67.2 % OOIP. This validates the recovery potential of guar gum for enhanced oil recovery.

Laboratory Formation Damage Test Data Upscaled With Computational Fluid Dynamics

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199268, “Upscaling Laboratory Formation Damage Laboratory Test Data,” by Michael Byrne, SPE, Lesmana Djayapertapa, and Ken Watson, SPE, Lloyd’s Register, et al., prepared for the 2020 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, 19-21 February. The paper has not been peer reviewed. Through several case histories, the complete paper demonstrates applications of computational fluid dynamics (CFD) modeling to upscaling of laboratory-measured formation damage and reveals implications for well and completion design. The value of laboratory testing is quantified and interesting challenges to conventional wisdom are highlighted. Introduction Laboratory formation damage testing is often used to help select optimal drilling and completion fluids. Test procedures such as sand retention and return permeability represent an attempt to simulate near-wellbore conditions during well construction and production. To determine what degree of permeability impairment is allowable, further interpretation that cannot be provided using classical nodal analysis or reservoir simulation methods is required. The complete paper describes the evolution of, and potential for, more-comprehensive upscaling and outlines the importance of consideration of full well geometry when designing and interpreting coreflood tests for formation damage. CFD simulations provide a means to upscale suitable laboratory test data to predict effect on well performance. Methods CFD simulations use a relatively simple, steady-state, static damage model that takes endpoint data from laboratory core tests and translates the data into parameters that are used for input into well geometry. Although this method has its merits and is a considerable advance on previous, more-simplistic upscaling attempts, it does not necessarily present the full picture of damage evolution in the near-wellbore. A transient model of damage with data again derived from laboratory coreflood data could reveal more about well cleanup and progressive damage removal. Steady-State Modeling. No API recommended practice for return permeability testing exists. Laboratories have their own procedures that comply broadly with recommended procedures developed some time ago. Operators and consultants, too, have their own procedures, which they often ask laboratories to follow. Although no recommended practice exists, evaluation of drilling and completion fluids usually involves measurement of a base permeability and remeasurement of a return permeability—or several—after application of the test fluid or fluids. In many cases, the laboratory removes the external mud cake or trims a slice of the end of the plug to measure return permeability without mud cake (Fig. 1).

Quantifying the Effect of De-Emulsifiers on Acid Treatment in Carbonate Formations

Matrix acidizing is a highly successful, effective, and relatively inexpensive approach to enhancing well productivity in carbonate formations. Accordingly, there has been little motivation to address the ways to optimize the acid stimulation process better. Acid-in-oil emulsions that form during this process cause one of the most challenging problems that negatively impact the performance and deliverability, especially when these emulsions are highly stable over extended periods. Such stable emulsions can plug the flow path of oil causing high resistance to flow and potentially reducing well productivity. De-emulsifiers are some of the most widely used acid additives targeting the reduction of emulsion stability. However, there is doubt in the research community on whether there is enough shear mixing that can cause the formation of emulsions inside the rock matrix. Besides, the effectiveness of de-emulsifiers in eliminating such emulsions in the pore space has not been investigated. In the current oil price market, there is a need to be more vigilant regarding the cost of well stimulation and the added value from the various additives. While laboratory work on matrix acidizing in carbonate formations is abundant, the work on oil-saturated samples is rare, and therefore, the effect of emulsions on the acidizing process has not been widely documented. In this work, we present a stacked study of bottle tests and core flooding tests designed to investigate the de-emulsifiers’ role in the rock matrix. The results reveal that (1) emulsion-risk in the pore space is real, and (2) the addition of de-emulsifiers to the acid allows for efficient backflow of oil, revealing an improvement in the performance of the acidizing treatment.

Anaerobic production of surfactin by a new Bacillus subtilis isolate and the in situ emulsification and viscosity reduction effect towards enhanced oil recovery applications

Emulsification and viscosity reduction effect of biosurfactants to crude oil are significant for enhanced oil recovery. Although biosurfactants for enhanced oil recovery were extensively studied, information on the anaerobic production of biosurfactants and its in situ effect to crude oil are still limited. Bacillus subtilis AnPL-1 was isolated from oil reservoirs production water and produced 150 mg/l of biosurfactants under anaerobic conditions. Sucrose and nitrate were favorable for anaerobic production of biosurfactants by strain AnPL-1. Strain AnPL-1 anaerobically produced biosurfactants at temperatures (20°C–50 °C), pH values (6–9) and 0–7% of NaCl. FTIR and HPLC-MS analysis showed that the anaerobically produced biosurfactants was a mixture of C13-, C14- and C15-surfactin congeners. Anaerobically produced surfactin decreased water surface tension to 28.5 mN/m with a critical micelle concentration of 30 mg/l. It can also emulsify crude oil with an emulsion index (EI24) of 70.5%. Strain AnPL-1 also produced 115 mg/l biosurfactants under simulated oil reservoirs conditions (anaerobic and 10 MPa conditions). Furthermore, strain AnPL-1 anaerobically grew well in the presence of crude oil. Strain AnPL-1 reduced the crude oil viscosity by 40.6% through in situ emulsification effect of produced biosurfactants. In core flooding tests, in situ biosurfactants production by strain AnPL-1 enhanced oil recovery of 9.98%. Although B. subtilis is a facultative anaerobe, anaerobic production of biosurfactants by B. subtilis for MEOR applications has been firstly studied. Without air injection, anaerobic production of surfactin by B. subtilis AnPL-1 is promising for in situ MEOR applications.

Synthesis of Sodium Ligno Sulfonate (SLS) Surfactant from Black Liquor Waste and The Potential Test for EOR in Ledok Field Cepu

Chemical injection in Enhanced Oil Recovery (EOR) with surfactants is known to reduce the value of Interfacial Tension (IFT) of oil and water which can increase oil mobility. EOR has been considered a promising technology to increase national oil production through the revitalization of existing wells in Indonesia, particularly in the Ledok field, Cepu. This study aims to test core flooding on a laboratory scale with EOR surfactant from biomass waste pulp industry, Black Liquor, from Sodium Lignosulfonate (SLS) on porous sandstone media. SLS is produced from lignin which is isolated from Black Liquor waste. In this study, crude oil from Ledok, Cepu, Central Java was used which was characterized first. To determine the effectiveness of surfactant performance before core flooding, several tests such as water stability test, IFT test, CMC (Critical Miselization Concentration) test, and filtration test have been carried out. For the core flooding test, a 1.5% surfactant concentration is injected continuously at 70°C. The core flooding results show that the compatibility test shows that SLS is compatible with Ledok’s natural formation water. Filtration tests show that SLS using membrane 42 produces larger FR solutions. The core flooding test results showed the best reservoir temperature for SLS surfactants was formulated at 70°C with a recovery of 87%. Therefore, the results show that SLS surfactants show promising results for sandstone media. Important for this research is the hydrodynamic study, studying the correlation flow rate of 4.06 Cm/sec, giving the Reynold value in the best porous medium of 0.3, and the best yield of 75% w/w.

An experimental study into rock dissolution mechanism during diluted seawater injection in carbonate rocks

Abstract Three decades has passed since the introduction of smart water injection in carbonate rocks; however, use of diluted seawater (dSW) and its associated mechanisms are not yet well understood. Several mechanisms have been introduced in the literature for increased productivity of low salinity water injection. In this study, coreflooding tests were conducted to analyze the importance of one of the contribution mechanisms, the so-called rock dissolution mechanism. We used seawater as the baseline injecting phase, along with two dSW solutions, 5- and 20-folds dilution ratios as the low salinity solutions. Several pore volumes of the displacing phase were injected into real reservoir core plugs to recover the oil content. The impact of rock dissolution on oil recovery was evaluated by measuring core plug permeabilities before and after the flood as well as the recovery factor (RF) as a function of time, along with monitoring pH of the displacing phase at the inlet and effluent. The interaction of rock and fluid was closely monitored and analyzed by studying the injection pressure profiles. It was obtained that diluting the seawater intensified the rock dissolution. This mechanism was absent when unprocessed seawater was used to recover the oil.

A Game Changer in Scale-Squeeze Technology

Background Field trials using a new scale-inhibitor technology that improves treatment lifetime of scale squeezes have been successfully performed in the Gulf of Mexico. Tomson Technologies, in partnership with Shell, developed proprietary nanoparticle carriers that enhance scale-inhibitor adsorption to the reservoir and control the return rate for extended periods of time. This technology results in less chemical bleed off in the initial flowback and increases the chemical retained in the reservoir, allowing for more effective squeeze treatments. Both nanoparticle-enabled phosphonate and polymer inhibitors have now been developed and successfully squeezed in the field. Phosphonate inhibitors are widely used for squeeze treatment due to their desirable adsorption and release properties in carbonate and sandstone reservoirs. Minor changes have been made to the chemistry, but overall, the fundamentals have remained unchanged for decades. Polymeric scale inhibitors have also been developed for cases in which phosphonates are not applicable. The nano-enhanced technology provides a large improvement of treatment lifetime of 2 to 4 times (200-400%) when compared to incumbents, making this technology advancement attractive even in cases where current squeezes are considered successful. The well selected for this case study is an offshore formation with a predominantly sandstone mineralogy (approximately 80% quartz) with 25-30% porosity and bottomhole temperature of 183°F (83°C). Technology From the Lab to Field A sandpack sample from the trial well was used in the laboratory to deter-mine the adsorption and desorption properties of the nano-enabled inhibitor in realistic rock conditions. Multiple conditioning steps were used before product was injected in a sequence that mimicked field squeeze treatments. Mass-balance results from the sandpack experiment show adsorption of approximately 8 mg of polymer retained per gram of crushed reservoir rock used in the experiment. A typical rule of thumb for phosphonate-scale inhibitors (only as a comparison since this is a polymeric scale inhibitor) is 1-2 mg of inhibitor retained per gram of rock. Therefore, this is considered a large improvement on adsorption. There are challenges associated with measuring polymers in brine as residuals; however, multiple methods, both in-house and external, were com-pared to ensure accuracy. The results using the nano-enhanced scale inhibitor show concentrations higher than 1 mg/L of active polymer for over 7,000 pore volume of return in the sandpack experiment. Complete intact core experiments were also conducted with reservoir fluids and showed no formation damage during the injection of the product with regained oil permeability of 96%. Oil permeability was in the 150-200 mD range for the intact core experiments. Third-party coreflood testing was performed with nitrified and foamed stages to ensure compatibility with the nano-enabled chemistry. No formation damage was observed with the nitrification of the stages containing the nano-enabled chemistry. Field Application Case Study After extensive lab validation of the product and supporting corefloods to de-risk the technology, Well A was selected by Shell to be the first well treated with the new nano-enabled extended-lifetime inhibitor.

Production of Biodegradable Sulfonated Methyl Ester by a Falling Film Reactor for ASP Flooding in EOR

Petroleum production can be improved through enhanced oil recovery (EOR) methods such as chemical injection. This study focused on sulfonation of methyl ester using SO3 dissolved in oleum compounds (H2SO4.SO3) in a mini-pilot falling film reactor at 70 °C and its application for chemical EOR with ASP flooding. The reactor was equipped with cooling water to facilitate heat transfer in view of the highly exothermic reaction. Biodegradable methyl ester sulfonate, a biosurfactant, was produced from esterification of vegetable oils, palm kernel oil, and coconut oil. The MES products were characterized by Fourier transform infrared testing, which showed S=O and -OH groups peaks, indicating that sulfonation had occurred. The IFT test data showed that the MES from CNO produced the lowest IFT values for light oil and heavy oil, equal to 11.4 mN/m and 10.3 mN/m, respectively. The effect of the MES concentration on the phase behavior was an increase of the IFT value before being applied in ASP flooding, and a decrease after reaching the optimum condition. The EOR core flooding test with the formulated ASP resulted in original oil in place (OOIP) percentages in the range of 12 to 23.5%. The highest acquisition was 23.53% OOIP for an ASP composition of 200 ppm, 0.5%wt, 2800 ppm, respectively.

Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

The relative permeability of coal to gas and water exerts a profound influence on fluid transport in coal seams in both primary and enhanced coalbed methane (ECBM) recovery processes where multiphase flow occurs. Unsteady-state core-flooding tests interpreted by the Johnson–Bossler–Naumann (JBN) method are commonly used to obtain the relative permeability of coal. However, the JBN method fails to capture multiple gas–water–coal interaction mechanisms, which inevitably results in inaccurate estimations of relative permeability. This paper proposes an improved assisted history matching framework using the Bayesian adaptive direct search (BADS) algorithm to interpret the relative permeability of coal from unsteady-state flooding test data. The validation results show that the BADS algorithm is significantly faster than previous algorithms in terms of convergence speed. The proposed method can accurately reproduce the true relative permeability curves without a presumption of the endpoint saturations given a small end-effect number of <0.56. As a comparison, the routine JBN method produces abnormal interpretation results (with the estimated connate water saturation ≈33% higher than and the endpoint water/gas relative permeability only ≈0.02 of the true value) under comparable conditions. The proposed framework is a promising computationally effective alternative to the JBN method to accurately derive relative permeability relations for gas–water–coal systems with multiple fluid–rock interaction mechanisms.