Tertiary Recovery Technology Research Articles

Enhancing ASP Flooding by Using Special Combinations of Surfactants and Starch Nanoparticles.

This study aimed to address the challenges faced by mature oilfields in extracting substantial oil quantities. It focused on improving the efficiency of alkaline-surfactant-polymer (ASP) flooding technique, which is a proven tertiary recovery technology, to overcome scaling issues and other hindrances in its large-scale implementation. Appropriate materials and their suitable concentrations were selected to enhance the ASP flooding technique. Special surfactants from Indonesia were introduced to improve the interfacial tension reduction and wettability alteration. Reservoir rock model that resembling Langgak oilfield in Sumatra was utilized, and low-salinity water was employed to mimic the oilfield conditions. Starches derived from cassava nanoparticles (CSNPs) and purple yam nanoparticles (PYNPs) were combined separately with conventional hydrolyzed polyacrylamide (HPAM) polymer to enhance its performance. Sodium hydroxide and sodium carbonate were used as alkaline in final ASP formula. It was demonstrated from this research that only two combinations of ASP formulations have led to improved oil recovery. One combination utilizing PYNPs resulted in 39.17% progressive recovery, while the other combination incorporating CSNPs achieved 35% incremental oil recovery. The ASP combination that resulted in recovery rate of 39.17% was composed of sodium hydroxide (NaOH) at a concentration of 1.28 wt.%, PSC EOR 2.2 (0.98 wt.%), and a combined polymer consisting of HPAM (0.2 wt.%) and PYNPs nano-starch (0.6 wt.%). The second combination led to 35% recovery rate and involved NaOH also at concentration 1.28 wt.%, PSC HOMF (0.63 wt.%), and a combined polymer comprising from HPAM (0.2 wt.%) and CSNPs nano-starch (0.8 wt.%). These findings of this study highlighted the potential of this modified ASP flooding to enhance oil recovery in mature oilfields, thereby offering valuable insights for oil industry.

Effect of water saturation on CO2 minimum miscibility pressure and oil displacement performance

The CO2 miscible flooding is an effective technology for development of low permeability reservoirs due to high oil displacement efficiency. However, CO2 miscible flooding for tertiary recovery technology typically occur after water flooding. Water hindered the contact and mass transfer of CO2 and oil, produce water resistance effect. Water can block CO2 and contact and mass transfer of crude oil (ie water blocking effect). The impact of this effect on the miscibility pressure and oil displacement effect is still unclear. In this study, homogeneous artificial cores with the same permeability as the reservoir were designed according to the miscible mechanism. Subsequently, the minimum miscibility pressure(MMP) between CO2 and crude oil at different water saturation was measured by the coreflood test. Based on the MMP, CO2 miscible flooding experiments were conducted by natural cores at different water saturation. The results showed that when the water saturation was 30%, 45%, and 60%, respectively, the corresponding MMP between CO2 and crude oil was 18.56, 19.48, and 21.76 MPa. The higher the water saturation, the longer the gas breakthrough time. But the oil recovery factor did not rise with the increase of water saturation. When the water saturation was 45%, the oil recovery factor in the miscible flooding experiment was the highest. In addition, the higher the water saturation, the weaker the CO2 extraction of various components in the crude oil. And the light components below C5 were most affected by water saturation. The mechanisms underlying these results are discussed. This study contributes to the development of CO2 miscible flooding reservoir plan.

Application of “oil-phase” microbes to enhance oil recovery in extra heavy oil reservoir with high water-cut: A proof-of-concept study

Microbial enhanced oil recovery (MEOR) is an important tertiary recovery technology to recover oil, especially heavy oil, from reservoirs. However, MEOR often fails to achieve satisfactory oil recovery in the field applications because of utilization of unsuitable microorganisms and nutrients. Recent studies proved the existence of microbes inside oil (“oil-phase” microbes) and their potential for application in MEOR. To validate this concept, we isolated microbes from the “oil-phase” of crude oil samples. With them, a synthetic four-member microbial consortium K, was selected to use in an experiment of core flooding, which showed a beneficial capacity for improving oil recovery. Furthermore, the consortium K and nutrients were applied in a field trial of microbial huff and puff in an extra heavy oil recovery. Results demonstrated the incremental cumulative oil production of two high water-cut (99%) shut-in wells reached 1078.8 t and 791.6 t, respectively, with the effective period of 14 months, while the viscosity of heavy oil had significantly declined decreased by 50%. In conclusion, our findings clearly demonstrate that the great potential of a novel methodology to use indigenous “oil-phase” microbes as seedbanks for improving oil recovery in extremely viscous oil reservoirs with high water-cut.

The Effect of Formation Water Salinity on the Minimum Miscibility Pressure of CO2-Crude Oil for Y Oilfield

CO2 miscible flooding is an important technology for enhancing oil recovery and greenhouse gas storage in the world. As a tertiary recovery technology, it is usually applied after water flooding. Therefore, the actual reservoirs usually contain a lot of injected water in addition to connate water. The salinity of these formation waters varies from place to place. CO2 is an acid gas. After it is injected into the reservoir, it easily reacts with formation water and rock and affects the physical properties of the reservoir. However, no research results have been reported whether this reaction affects the minimum miscibility pressure (MMP) of CO2-crude oil, a key parameter determining miscible flooding in formation water. Based on CO2-formation water–rock interaction experiments, this paper uses the core flooding method to measure the CO2-crude oil MMP under different salinity in formation water. Results show that CO2 causes a formation water pH decrease from 7.4 to 6.5 due to its dissolution in formation water. At the same time, CO2 reacts with formation water, albite, potassium feldspar, and carbonate minerals in the cores to generate silicate and carbonate precipitates, which could migrate to the pore throat together with the released clay particles. Overall, CO2 increased core porosity by 5.63% and reduced core permeability by 7.43%. In addition, when the salinity of formation water in cores was 0, 4,767, and 6,778 mg/L, the MMP of CO2-crude oil was 20.58, 19.85, and 19.32 MPa, respectively. In other words, the MMP of CO2-crude oil decreased with the increase of salinity of formation water.

Multi-Stage Optimization Approach for Polymer Flooding Optimal Control Problems⋆

AbstractPolymer flooding is an important tertiary recovery technology. The optimization of polymer injection can be formulated as an optimal control problem. Since the polymer injection has special slug structure, the size of slug and injection concentration must be optimized, simultaneously. Thus in this paper, a multi-stage optimization approach based on the control vector parameterization (CVP) is proposed for solving this optimal control problem. A piecewise-constant approximation is used to describe the injection structure in which each constant piece represents an injection slug, and the optimization problem can be solved as a nonlinear programming (NLP) problem. For illustration, an experiment example is solved by using the proposed approach.

Short-Radius Lateral Drilling System

Abstract Development of a rotary-guided short radius curve drilling tool is described. Improvements over prior tools include an anti-whirl PDC bit, a stronger and smoother flexible joint, a signalling valve to assist in tool face orientation, and a computer-aided system to monitor orientation while drilling. The tool drills a smooth radius of curvature which conforms to a simple relationship between the bit tilt angle and the distance between two points of contact with the wellbore. The authors advocate using this type of tool to economically enhance oil recovery in mature fields by laterally recompleting existing wells. Eight short radius lateral wells were drilled at 5000 ft depth in West Texas during field testing of the tool. Introduction There are numerous mature oil fields in the United States and other countries that are experiencing declining production. Unfortunately, even after the latest enhanced recovery methods are utilized, vast oil resources will be left unproduced. Lateral wellbores drilled from existing wells offer the potential to drain more oil than would be recovered otherwise. Laterals may be used to tap fresh oil by intersecting fractures, penetrating pay discontinuities, and draining up-dip traps. Lateral recompletions can correct production problems such as water coning, gas coning, and excessive water cuts from hydraulic fractures which extend below the oil-water contact. Synergistic benefits may result from coupling lateral recompletions with enhanced recovery techniques to solve conformance problems, contact unswept oil by recompleting injection wells, and to redirect sweep by converting existing well patterns into line-drive configurations. Lateral recompletions strategies can take advantage of the current production infrastructure, capital resource of existing wellbores, known resources of oil in place, and secondary and tertiary recovery technology. A major impediment to the widespread use of lateral re-entries is that drilling and completion of the laterals must be done relatively "cheaply." Workover economics in mature fields require substantial cost reductions over the methods most often used for drilling new horizontal wells. The need for a reliable reduced-cost drilling system that utilizes the equipment and cost structures of workover and repair services provided the impetus for a development and field test program in West Texas where laterals were drilled in 8 wells. This paper primarily discusses development of the curve drilling portion of the re-entry system. Even though this is a small part of the overall effort to place a re-entry lateral in a well, it is a critical and costly part. Once the curve is drilled, the lateral is rotary drilled with a somewhat more conventional stabilized bottomhole assembly and the same articulated drillstring that is used for curve drilling. Curve Drilling Tool Background For a re-entry drilling system to be technically successful it must be capable of drilling a consistent radius of curvature and drilling the curve in the desired direction. These requirements arise from the necessity to (1) position the end of the curve within a precise depth interval so the lateral can traverse the payzone as desired, (2) place the lateral in a direction dictated by well spacing, desired sweep pattern, or other geological considerations, and (3) to establish a smooth curve to facilitate drilling the lateral and completing the well. P. 693^

Microbially enhanced oil recovery from carbonate reservoirs

Abstract About half of the world's oil production is from carbonate formations. However, most of the research in microbially enhanced oil recovery (MEOR), a potentially important tertiary recovery technology, has focused on sandstone reservoirs because, in general, they are geologically simpler than carbonate reservoirs and easier to model in the laboratory. Carbonate formations have a wide range of pore geometries and distributions, resulting in complex flow dynamics. The low matrix permeabilities and the dual porosity characteristics of most carbonate formations, coupled with the chemistry of carbonates, have slowed implementation of enhanced oil recovery methods. A review of the data on carbonate reservoirs in Dwight's Energydata TOTL System indicated that 40% of the oil‐producing carbonate reservoirs surveyed in the United States have environmental, geological, and petrophysical conditions that would make them candidates for MEOR. A review of a number of MEOR field trials showed that rates of oil prod...