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Water injection fields account for over half of Malaysia’s oil production, with most of these fields at matured waterflooding stage. Low sweep efficiency due to water conformance where reservoir with high heterogeneity might cause premature breakthrough is one of the issues that leads to low oil recovery. In this study, we described the comprehensive experimental analysis to substantiate waterflooding performance in heterogeneous reservoirs by evaluating the flow diversion chemical (FDC) as a water conformance agent at high temperature.Chemical characterization, rheology, particle size analysis, compatibility, and thermal stability were evaluated for FDC according to the prevailing mechanism. Afterward, an experiment to simulate the reservoir environment was conducted to estimate oil incremental and blocking mechanism, in terms of residual resistance factor (RRF) performance in the intended field condition.The test was innovatively set up using commercial outcrop and reservoir native cores in dual-core permeability systems to test high permeability and low permeability porous media at high temperature up to 115°C temperature to mimic the conformance process. Typical single core flooding test are only able to determine the potential of the blockage mechanism by determining the RRF, without the diversion effect to quantify the additional oil recovery from the flow diversion process. The setup uses cylindrical preserved core plug samples with permeability contrast ranges from 100mD to 2 Darcy and tested at 115°C. The customized coreflood design successfully mimicked the conformance process. In our study, the RRF of 186 and cumulative oil recovery of 52% with an incremental oil recovery of >5% was obtained by the FDC injection.The study provides an innovative way in the coreflooding experiment to evaluate the performance of a conformance control agent in a heterogeneous reservoir with high temperatures.

Fines migration is a recognized as one source of formation damage in oil and gas production wells. A newly fine stabilizers chemical was developed and applied to prolong oil well productivity by adhering the migrating fines to the pore surfaces and reducing the tendency for mobilization as observed in the laboratory. The paper presents the successful pilot application and monitoring process of newly developed fine stabilizer in an oil well with has a history of rapid decline after several times of stimulation.A screening process to identify pilot well was carried out into well "C". The well was natural flow for almost 2 decades but in last 8 years, it showed a sharp oil productivity decline after several times workover (re-perforation). A series of experiments were performed to identify the root cause of the rapid decline of the oil well and concluded due to migrating clays. The newly fines stabilization chemical was developed which has a purpose to prevent detachment of those fines and prolong the formation structure integrity by keeping the fines stuck on the rock surface. The workflow breakdown design structure for injection and monitoring were carried out to ensure the well achieve the agreed objective that was to increase back production by reperforation job and to reduce production decline rate by 90% for the first 6 months and 30% afterwards.As a first pilot, well "C" has the main target to delay the production decline after re-perforation due to fines migration as concluded based on root cause analysis of formation damage from comprehensive laboratory experiments. The novel inhouse fines stabilization chemical was introduced as damage remedial by neutralizing fines migration through microflocs and coagulated fines as solid. It was injected near the wellbore around 4-5 ft. and monitored for 6 months. The sampling was taken regularly to measure produced clay and sands and compared with the pre-treatment results. The particle size measurement showed if the produced particles decreased significantly. The post-treatment of fine stabilizer chemical shows that it can prolong oil well productivity by delaying the decline rate to 1.5%/month for 6 months monitoring period and even stable over 1 years, which means exceed the expectation.The successful result of well treatment using newly fine stabilizers chemical has unlocked additional oil production and prolong well life.

The slug flow regime typically forms during multiphase flow in subsurface and surface facilities, which can result in severe flow capacity losses. The foam injection is a proposed method to control and remove slugging in the wellbore and nowadays, the foam application has been extended to controlling the slugging in the pipeline transportation. Prior to a pilot deployment in an offshore Field "S", this study describes a technological assessment review of a newly designed internal foam chemical to control slugging. This application for controlling foam slugs aims to eliminate hydrodynamic slugs that constantly form at Field "S" due to wave instability at gas-liquid flow rates. Based on liquid level trending at surface facilities platform of Field "S", a slug flow regime was observed from severe fluctuation trending. Technology assessment was conducted using inhouse guidelines that aim to shorten overall pilot deployment to initiate testing as early as possible. The laboratory experiment was performed including compatibility tests. The foam stability and interfacial tension (IFT) were carried out using Teclis Foamscan and Grace spinning drop tensiometer, respectively. Meanwhile, the rheology characterization of foam was conducted using a Foam rheometer for the viscosity test. A slug flow regime was discovered based on severe fluctuation trending at surface facilities platform of Field "S" for liquid level trending. Utilizing internal guideline designed to hasten the entire pilot deployment and start testing as soon as possible, technology assessment was done. A pressurized foam Rheometer was used to measure the foam dynamic viscosity, and it measured about 5.2 cP at a shear rate of 1000 s-1. The IFT measured lower than with water and other commercial foamer. When the foam chemical, defoamer, and demulsifier were tested for compatibility with production chemicals such scale inhibitor, corrosion inhibitor, and biocide, neither precipitation nor separation was seen. The recently developed foam chemical may help to further reduce corrosion from 0.17 mm/y to 0.05 mm/y. The technical, operational, health and safety, and environmental major unknown elements of this newly designed technology have all been evaluated and identified. Foam created by foam injection is a main challenge with this method, but it has been overcome by finding the right demulsifier and defoamer. Based on this study, a newly developed foam chemical has been identified as a potential to be deployed in reducing liquid slugging in the pipeline. If slugging can be effectively controlled, value creation will result from an increase in gas and liquid production as well as the avoidance of pipeline maintenance and repair.

The scale problem is turning into a fluid-related flow assurance concern in oil and gas wells at various locations in the Malaysian basin. Flow assurance issues can have a severe influence on the total fluid production trip from subsurface to surface. Oilfield scale comes in different varieties, including organic, inorganic, gas, soap, and mixed scales. In the past, there was only one type of scale dissolver chemical that could be used, making it less efficient to dissolve multiple types of scales at once. The evaluation of a recently developed, so-called robust solid dissolver (RSD), from the lab to a pilot deployment, is presented in this work. The RSD technology was developed based on a stable micro-emulsion solution that comprises acid and solvent components. Near the wellbore and along the tubing string of an oil well, it can concurrently dissolve organic and inorganic scales. After extensive visual analysis and laboratory experimentation, it was determined that the mixed scales issue was the cause of the oil production's rapid decline. This conclusion was supported by laboratory analysis and observations made from the wellsite throughout the tubing string and near wellbore casing. Based on laboratory tests, RSD can dissolve mixed scales 100% in 24 hours at well temperature and no incompatibility issue with production chemicals and all the pumping/wireline components. The RSD was developed based on the total organic system that can prevent corrosion, is compatible with hydrocarbon. The RSD was piloted at oil well "1" at Field PN and executed successfully to remove mixed scales and the well was revived. Based on result from the first Pilot, it revived oil well, increased production at a certain level. By increasing oil production rate and having value creation as a single chemical treatment to address mixed scales concerns, the new RSD has unlocked its potential to revive the well due to mixed scale issues.

A novel developed fines stabilizer (FS) chemical was used to successfully treat an oil well by reducing the decline rate from 17% per month (pre-treatment) to 1.5%/month (post-treatment for a 6-month monitoring period). Following this success story, more qualified candidates are flocking to replicate it. As a result, the challenge now is to predict each candidate's post-treatment performance. The paper focuses on the development of numerical modelling of a fine stabilizer chemical using a chemical reaction approach to understand the mechanistic process and will serve as a benchmark for future technology replication performance prediction. The mechanisms of the novel developed FS chemical were observed in the laboratory through fine particle coagulation and flocculation. The methodology of this study is to translate the mechanisms and key features associated with observed laboratory data into a scripted chemical reaction program that was coupled with a numerical reservoir simulator. Prior to well modelling, laboratory coreflooding data were validated. To properly represent the mechanistic process with a chemical reaction approach and capture the near wellbore effect, a single well model with local grid refinement was developed. The chemical reaction feature provides a versatile toolbox for modeling complex processes involving chemical and physical interactions. The actual production data history matching process with was carried out to investigate key important parameters. The FS chemical reaction was divided into two stages: damage and treatment. The damage was defined as fines deposited in the pore throat plugging and reducing permeability near the wellbore. Fines migration frequently indicates a build-up of fines in the near-wellbore region over time. As a result, the damage caused by these deposited fines reduces permeability. The novel FS chemical will remove deposited fines through micro-flocs and coagulating fines as solid. The history matching process was completed for core data and the mechanistic model with production and pressure data, and acceptable matches were obtained using rate control. The mechanistic model was tested with constrain at bottomhole pressure for few months historical data. It can predict the production performance with good accuracy compared to actual welltest data. Key parameters of FS injection were observed because of this research and can be used as a benchmark in the future to demonstrate the concept of extending oil well productivity and predicting field replication to recurrence the success story.

The deployment at the field-scale of a novel technique to improve oil recovery using nanoparticles injection is challenging. It requires a comprehensive evaluation of a series of laboratory experiments, to translate and validate the mechanisms into a numerical model to predict accurately and reduce uncertainty parameters. This paper describes the application of novel advanced reservoir modeling for nanoparticles from pore-scale to field-scale, using an offshore Malaysian oilfield as a pilot field case. A series of laboratory experiments (fluid-fluid and fluid-rock) and numerical studies: nanofluid formulation, pore-scale studies, validation, and upscaling process into the field-scale model were carried out. The development of nanofluids was formulated to meet key criteria such as compatibility and thermal stability at the intended field condition. Prior to coreflooding tests with native core, a series of experiments to observe mechanisms were carried out. The results of the laboratory experiments were then validated in the 1D coreflooding model. The procedure was continued with observed critical parameters being scaled-up into 3D field-scale model before running the prediction scenarios. The newly developed nanofluids for the intended field performed well in compatibility and thermal stability tests at reservoir temperature. Precipitation and sedimentation were not observed in this solution. The wettability alteration to more water-wet was observed with consistent results through interfacial tension measurements, contact angle measurements, and relative permeability measurements. Coreflooding was performed using native core, and the reduction of residual oil saturation was approximately 25% between pre- and post-nanoflooding. The adsorption of nanofluids was measured to be around 1.12 mg/g of rock. All these results were input into the model and the history match quality index achieved an acceptable match of ~95%. Several critical parameters for the upscaling process were investigated such as reaction rate of particle aggregation, adsorption, and retention factor. During the scale-up process, the velocity of the fluids and pressure drop were conserved because the recovery is sensitive to flooding rate and the viscosity of the fluids are pressure dependent. The field-scale model was run for the intended field location. The potential of using nanoparticles was evaluated and compared to the no further activity scenario giving an additional recovery factor of approximately 1% per year. The developed method of novel robust advanced reservoir modeling for nanoparticles creates a new reference as the first application in the world of novel advanced numerical modeling at field-scale.

The nanoparticles are considered as an attractive emerging improved oil recovery technique in last decade due to its ability to propagate deeper into pore throat and displace unswept oil in the reservoir. Current understanding of its mechanisms in conventional oil has been observed so called disjoining pressure that involved wettability alteration, log-jamming, and viscosity effect. This paper presents recent investigation of new potential mechanism during development of nanofluids to improve oil recovery in Malaysian oilfield. The new inhouse nanofluids was developed using acrylamide monomers that were grafted on the surface of silica-based nanoparticles. A minor concentration of surfactant was introduced into the formulation to observe synergistic effect. The nanoparticles were characterized under electron microscope. Compatibility and thermal stability tests were conducted using reservoir fluids at reservoir temperature. The rheology of fluids was measured during monitoring of stability. In term of wettability alteration, sequence fluid-fluid and rock-fluid tests were conducted includes dynamic interfacial tension (IFT) and optical contact angle (OCA) measurement. The particle size was measured with size around 20 nm. Adding small concentration of additive showed good performance in term of compatibility, thermal stability, and wettability alteration through IFT reduction and OCA measurement. Nanofluids with additive provided excellent compatibility with reservoir fluids and stable at reservoir temperature over 60 days. Its viscosity was also more stable during observation period without creating micro-emulsion. The IFT reduced insignificantly from 2.6 to 1 mN/m and when introduced additive, the IFT reduction achieved 0.01 mN/m. This synergistic effect was observed during IFT measurement and called as fragmentation. Our recent finding leads to provide new reference for displacement mechanism using next generation of nanofluids and offers further potential of nanoparticles with multiple mechanisms and rapid synergistic effects prior its application in in Malaysian oilfield.

A naturally flowing well "C" was experiencing a sharp oil productivity decline (13%/month) and skin build-up was observed from well testing to ascertain quantitatively whether damage occurs. Meanwhile, asphaltenes and paraffins are well-known as the primary sources of organic deposition that can compromise the well's flow assurance, occurring not only in the wellbore but also in the reservoir pores, reducing flow efficiency and clogging the flow paths. This paper discusses an integrated workflow for determining the root cause of damage in the well. Thus, the remedial strategy can be better defined. Laboratory testing is crucial to identify the root cause of damage. The integrated laboratory experiments were designed to elucidate, diagnose, and mitigate the damage mechanism. In this study, it was divided into 3 integrated tests: rock solids (inorganic), fluids (organic), and mixtures (wax). The X-ray diffraction (XRD) technique was used to determine mineral compositions of rock. The particle size dispersed in reservoir fluid were measured through dynamic light scattering instrument. The properties and precipitations of organic and mixtures were measured. Water composition and crude oil were analysed and characterized through saturate, asphaltene, resin and aromatic (SARA) analysis. The colloidal stability index was determined from SARA analysis and considered stable. The composition of water was determined to contain only 20 ppm of calcium carbonate. The wax content, pour-point and wax apparent temperature were measured at 1.61%, 6°C, and 12°C respectively, which was significantly lower than the flowing tubing head temperature. Therefore, the potential damage caused by organic and mixtures deposition can be minimized. This well was being produced from sandstone rock, there was no obvious evidence of sand being produced into the surface, which was consistent with observations from a neighbouring well producing from a similar formation. Sand production was measured around 9-15pptb, which was classified as an obscurely produced sand problem. The mineralogy of the formation has been determined using XRD analysis both from the observed well and a neighbouring well. Both wells demonstrated consistency when the clay content was 20-30% with the major clay type observed as migrating clay (>50%) and minor as swelling clay ( The workflow can identify the root cause of formation damage in this well, which is a mechanical mechanism caused by fines migration. Treatment with a fine stabilizer may be chosen to prolong the productivity of the well. This workflow can be used as a practical guide for determining the source of formation damage via integrated laboratory experiments.