The Research and Application of Adjustable Drive Improve Oil Recovery Technology in Ansai Low Permeable Fracture Reservoir

Reservoirs of high viscosity and low permeability are abundant and widely distributed in various countries, which can contribute an important percentage of oil output in the world. Conventional chemical flooding are suitable for low viscosity oil (less than 30 mPa·s) and medium/high permeability reservoirs (more than 50mD). However, it is a great challenge to applied chemical flooding technology for higher viscosity (30-500mPa·s) oil and lower permeability (1-50mD) reservoirs. On the one hand, the high contents of resin and asphaltene, or the formation of wax crystals in low reservoir temperature, lead to high oil viscosity and low oil recovery; On the other hand, low permeability can cause injection difficulty, and conventional chemical agents (polymers and formulations of chemical combination flooding) are difficult to inject. At present, the main exploitation mode is water flooding. However, because of high oil viscosity and low oil fluidity, the water flooding recovery is only about 15%. So it is very necessary to develop effective development technology. It is a good choice to develop water flooding with the intelligent viscosity reducer to decrease oil viscosity and improve oil fluidity, which has small molecular weight and can inject low permeability reservoirs easily. The performances of the viscosity reducer were studied in detail, including viscosity reduction efficiency, tripping oil film capacity, interfacial property, oil-displacement efficiency etc. The novel viscosity reducer with intellectual property show excellent properties. The viscosity reduction efficiency of the viscosity reducer was more than 80% (from 64.4 mPa·s to 10.3 mPa·s), and it could strip oil film within 40 seconds quickly, and could achieve ultra-low Interfacial Tension (IFT, less than 1.0×10-2mN/m).Alkali (NaOH or Na2CO3) could help to increase the viscosity reducing effects, and improve the stripping oil film capacity and interfacial property.The viscosity reducer had high oil-displacement efficiency; after water flooding, Oil recoveries increased 23% (OOIP, Original Oil In Place) with thehelp of this viscosity reducer.The novel viscosity reducer has viscoelasticity and shear-thinning ability. The monomer molecules can form the three-dimensional network structure in aqueous solution with high viscosity, which plays a role in enlarging the swept volume. With the increase of the shear rate, the three-dimensional network structure is broken down into the monomer molecules, and the viscosity decreases rapidly, so the viscosity reducer solution can inject low permeability reservoir easily.Compared with conventional polymer and polymer-surfactant, this viscosity reducer solution had better shear resistance and injectivity, and could filter membrane (0.2μm pore) effectively. The novel viscosity reducer can substitute for conventional polymer and polymer-surfactant in chemical flooding. This paper provides insights of a new effective EOR way for high viscosity and low permeability reservoirs.

Aiming at the problems of enhanced reservoir homogeneity, severe injection water breakthrough and low oil production after polymer flooding in Bohai B oilfield, through laboratory research and evaluation, two heterogeneous composite systems: FJX-1 and FJX-2 were optimized, and the profile control and profile control performance evaluation, and displacement efficiency analysis of heterogeneous combination flooding in high water cut stage after polymer flooding in offshore oilfield have been studied. The results show that the plugging efficiency of polymer, FJX-1 and FJX-2 compound profile control and flooding systems are 61.42%, 83.45% and 93.17% respectively. The composite viscosity and elastic modulus of FJX-2 profile control and flooding system are better than those of polymer and FJX-1 profile control and flooding system, indicating that its plugging performance and viscoelastic performance are the best. Compared with the fluid flow diversion ability, after injection of polymer with FJX-1 and FJX-2 composite system, the liquid production fraction ratio of high and low permeability layers decreased from 87:23, 89:21, 88:12 to the lowest 61:39, 48:52 and 35:65, respectively. In the subsequent water flooding process, after FJX-2 composite profile control, the liquid yield ratio of high and low permeability layers in core can still reach 66:34, which indicates that the plugging effect of FJX-2 composite profile control and flooding system for high permeability layers is obvious. From the oil displacement experiment, it can be seen that the lowest water cut of the three systems in the process of water flooding is 54.58, 52.97 and 44.39, respectively. After polymer flooding, the oil recovery can be increased by 6.32% and 11.84% respectively to continue FJX-1 and FJX-2 composite profile control flooding. The case comparison shows that the best combination of profile control and profile control slug is profile control (1500 mg/L PL + 1500 mg/L JLJ) + profile control (1500 mg/L RY + 300 mg/L PPG). The profile control and displacement performance of heterogeneous composite system can not only make use of crude oil in medium and low permeability reservoirs, but also exert displacement effect on some crude oil remaining in reservoirs through effective plugging of high permeability reservoirs. At the same time, field tests also show that heterogeneous composite flooding has broad prospects for development in offshore oilfields. The profile control and displacement performance of heterogeneous composite system can not only put crude oil in medium and low permeability reservoirs to be used, but also some crude oil remaining in the reservoir can be displaced through effective plugging of high permeability reservoirs. At the same time, field tests also show that heterogeneous composite flooding has broad prospects for development in offshore oilfields.

Nano-particles possess desirable attributes such as small particle size, excellent injectivity, and migration performance, making them highly compatible and adaptable for addressing the water flooding requirements of the low-permeability oil reservoir. When selecting an oil displacement agent for enhancing water flooding and improving oil recovery, factors such as injectivity and migration need to be carefully considered. In this study, through a comprehensive analysis of the mechanism and technical characteristics of nano-particle oil displacement agents, the plugging and profile control mechanisms recognized by the mainstream of nano-particles are elucidated. By examining various elements including outcrop fractures, natural micro-fractures, artificial support fractures, and dynamic monitoring data, a reevaluation of the dominant channel scale governing water drive in low permeability reservoirs is conducted, thereby defining the target entities for profile control and flooding operations. Drawing upon Darcy’s percolation law and leveraging enhanced oil recovery techniques based on the classical Kozeny equation, a profile control and flooding mechanism is proposed that focuses on increasing the specific surface area of polymer particles while simultaneously reducing reservoir permeability. This innovative approach establishes a novel matching method between nano-polymer particles and the diverse media found within the reservoir. Lastly, the application of nanoparticle flooding technology in Changqing Oilfield is presented, highlighting its practical implementation and benefits.

CO2 injection into reservoirs for enhanced oil recovery and sequestration is the most efficiency way to realize the carbon neutrality goal. Various types of reservoirs could be the targets for CO2 sequestration but which one should be the best choice is still unclear, especially for the huge reserves of heavy oil reservoirs and low permeability reservoirs. The sealing property of cap rock, displacement efficiency of CO2 flooding and CO2 dissolution ability in the oil jointly determined the CO2 sequestration potential. This work compared the CO2 sequestration potential between heavy oil reservoirs and low permeability light oil reservoirs via a series of experiments and numerical simulations. The breakthrough pressure of CO2 in the caprock, the CO2 dissolution amount in heavy oil and light oil and oil displacement effective by CO2 flooding were investigated to evaluate CO2 sequestration capability via the dissolution and capillary trapping in two types reservoirs. Moreover, the numerical simulation of CO2 flooding in a heavy oil reservoir and low permeability reservoir were performed based on the above experimental data to quantitatively clarify the CO2 sequestration potential. The breakthrough pressure of the mudstone caprock of the low permeability reservoir was 3.5 times higher than that of the mudstone caprock of the heavy oil reservoir, which indicated the CO2 sequestration pressure in the low permeability reservoir was higher than that in the heavy oi reservoir. The solubility of CO2 in the heavy oil was 2 times lower than that in the light oil. The CO2 sequestration amount per unit pore volume in the low permeability light oil reservoir was slightly higher than that in the heavy oil reservoir under a certain temperature and pressure condition, and it increased while temperature increased due to the incremental displacement efficiency of heavy oil. The proportion of CO2 sequestration by capillary trapping in low permeability cores could reach 87% while the CO2 sequestration by dissolution in the heavy oil reservoir was nearly 30%. Numerical simulation found that in the real reservoir conduction, the residual trapping proportion in the low permeability reservoir was lower than that in the heavy oil reservoir but the effective sequestration coefficient of low permeability reservoir was larger than that of heavy oil reservoir. We expect this work could point out the application direction for the CO2 enhanced oil recovery and sequestration.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 158562, ’Optimizing Fracture Stimulations in Low-Permeability Oil Reservoirs in the Ordos Basin,’ by Xinghui Liu, SPE, Pinnacle—A Halliburton Service; Yanrong Chang, Hongjun Lu, Baochun Chen, Jianshan Li, Yin Qi, and Chengwang Wang, PetroChina Changqing Oilfield Company, prepared for the 2012 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 22-24 October. The paper has not been peer reviewed. Huge low-permeability oil reserves are found in the Ordos basin in China. Key characteristics are low reservoir quality (10 to 13% porosity), low permeability (0.3 to 2.0 md), and low reservoir pressures (pressure gradients of 0.0075 to 0.009 MPa/m). Fracture stimulation is essential for commercial production in these reservoirs. To understand fracture-growth behavior better and to optimize treatment designs, microseismic monitoring and fracture modeling were performed for pilot wells in key areas. In some reservoirs in the basin, fracture-closure stress sometimes could not be obtained from commonly used pump-in/shut-in tests because pressure decline is extremely slow. To obtain closure stress in these reservoirs, conventional pump-in/flowback (PI/FB) tests were modified and used. Fracture-modeling analysis then was conducted with a calibrated fracture model, which must match both the observed net fracture pressures and the fracture dimensions from microseismic mapping. This approach led to significant improvements in fracture-treatment designs in these tight oil reservoirs. Introduction The Ordos basin is a lacustrine/fluvial and sedimentary basin in northern China and covers approximately 370 000 km2 across the Shaanxi, Gansu, and Shanxi provinces, and the Ningxia and Inner Mongolia autonomous regions, as shown in Fig. 1. Oil reservoirs are found at depths ranging from 800 to 2800 m in the south, and natural-gas reservoirs are found at depths ranging from 2700 to 3600 m in the north. Oil reservoirs are mainly Triassic and Jurassic systems, while natural-gas reservoirs are mainly Permian and Ordovician systems. The Ordos basin also has abundant coal and coalbed methane. Fracture stimulation of the low-permeability oil reservoirs in the Changqing oil field of the Ordos basin was studied. Changqing oil field is a general term that represents many individual oil fields across a large area. Oil production in the Changqing oil field started in 1971. During early development, oil was produced only from reservoirs with relatively good properties (permeability of 10 to 100 md) in the Jurassic formations, and small-scale fracturing treatments were necessary to remove near-wellbore formation damage. In recent years, these Jurassic reservoirs with relatively good properties have been depleted. Currently, the Triassic reservoirs with poorer reservoir properties account for more than 85% of the proved oil reserves in the Changqing oil field. The Triassic reservoirs are characterized by low reservoir quality (10 to 13% porosity), low reservoir permeability (0.3 to 2.0 md), and low reservoir pressures (pressure gradients of 0.0075 to 0.009 MPa/m). Development of the low- permeability reservoirs in the Changqing oil field began in the 1990s, while the large-scale development of ultralow-permeability reservoirs began in 2008. Production from these reservoirs requires the use of fracture stimulation.

Low permeability oil reservoirs hold an important position in the global oil resource reserves. They boast abundant reserves and serve as one of the crucial sources for crude oil reserve replacement in China and even the world. The mechanisms for improving the oil recovery rate in high-oil-bearing reservoirs include improving fluid properties, enhancing displacement efficiency, etc. However, their development is quite challenging, requiring continuous exploration and innovation in development technologies. This study addresses the unclear distribution patterns of microbial communities and the incomplete understanding of microbial enhanced oil recovery (MEOR) mechanisms in low permeability reservoirs. Utilizing high-throughput genomics and functional gene analysis techniques, combined with laboratory and field data, the study investigates the distribution and growth patterns of microbial communities in a low permeability reservoir, exemplified by the S169 block. Additionally, the potential of MEOR to enhance oil recovery and its underlying mechanisms are explored. The results indicate that microbial communities in low permeability reservoirs exhibit strong heterogeneity, with their distribution closely correlated to geological factors such as reservoir permeability and porosity. The diversity of microbial communities is positively correlated with oil recovery efficiency, and highly active microbial populations promote the production of metabolites that enhance oil recovery. The metabolic products of microorganisms help reduce the interfacial tension between oil and water, improve the fluidity of oil, and enhance the recovery rate. In addition, the structural changes in microbial communities are closely related to factors such as the permeability and porosity of reservoirs. This study provides a theoretical basis for the optimization of microbial enhanced oil recovery (MEOR) technology.

A new microspheres-surfactant flooding system consisting of polymer microspheres and nonionic surfactant has been detailed to enhance oil recovery of Bohai oilfield by increasing the sweep efficiency of water and the oil displacement efficiency of surfactant synchronously. The surface morphology and particle size distribution of polymer microspheres have been investigated through scanning electron microscopy and dynamic lighting scattering. In addition, plugging performance, oil displacement efficiency and the deep profile control process of combination system have been studied by utilizing assembled parallel double cores models and core displacement experiments. The experimental results have shown that the initial appearance of the polymer microspheres was regularly spherical; the particle size distribution was from 200 nm to 6 μm. The particle size of the microspheres after swelling was increased by nearly five times compared with the original particle size. The combination system could exhibit an effective injectivity and plugging effect for cores with different permeability from 0.5 μm2 to 3.0 μm2. This system could significantly reduce fractional flow through high permeability channel, and also present good profile control effect and oil displacement efficiency in parallel double cores. By the injection of the 2.5 PV microspheres solution, the microspheres flooding recovery could improve about 34% more than water flooding. The slug composition, with 400 mg/L polymeric microspheres and 0.3% nonionic surfactant, could obtain a higher oil recovery by 4 wt% original oil than the microspheres system. The combination system could be recommended as a potential combination for profile control in Bohai heterogeneous reservoirs.

Understanding oil and gas production from low-permeability sandstones requires an understanding of the porosity. This paper reviews the analysis of data from hundreds of cores’ microscopic pore characteristics of low-permeability sandstone reservoirs from Chang 6 reservoir of Ji-yuan oilfield in ordos basin. And this paper is to embody the methods used in the study of low permeable sandstone reservoir in recent years and the results reflected in it. For example, by analyzing the rock of Chang 6 reservoirs, it can be seen that the rock of Chang 6 reservoirs is mostly developed by Feldspar Sandstone, its internal pore types are diverse, the pore size is mainly small pore type, the second is fine pore, and has continuous spectral distribution, and the distribution is single peak shape. Different methods have been used to study low-permeability sandstones, including scanning electron microscope, casting thin plate, physical test means, high-pressure mercury, constant velocity mercury, NMR experiments. The results show that the pore-throat combination types of reservoir are mainly small pore-micro-larynx. The main type of reservoir throat is mainly flaky throat. The extremely strong heterogeneity in the layer is the key to the efficiency and effect of water flooding. Therefore, the exploration and development of low permeable sandstone reservoirs can be guided by the analysis of relevant parameters.

Various researches on laboratory and field scale illustrate that manipulating the ionic composition and the ion concentration of injected water can affect the efficiency of water flooding and the interaction of injected water with rock and other fluids present in porous media. The objectives of this paper are to investigate parameters that affect low salinity water flooding; mainly the effect of injecting water salinity on and the potential of low salinity water flooding for oil recovery in secondary recovery mode are studied. The effect of pH and differential pressure across the core are used to explain the mechanism of fine migration phenomena. The recovery results of formation water injection were compared for the seawater, formation water with a salinity of 0.1 and 0.01, and when divalent ions were removed from the formation water with a salinity of 0.01 to investigate the effect of divalent ions on oil recovery. Different types of crude oil were used for investigating the effect crude oil properties on oil recovery. Seawater injection resulted in lowest oil recovery of 2.6% and the reduction of water salinity of formation water from 0.1 to 0.01 resulted in an improvement of 4% and 7.7% in oil recovery respectively. Removing divalent ions from the injected water decreased the improving effect of low salinity water flooding. In addition, both types of crude oil responded to low salinity flooding and no straight correlation was seen between acid number and the improving effect of low salinity water flooding.

Low permeability reservoirs are characterized by low permeability, small pore throat, strong heterogeneity, and poor injection-production ability. High shale content of the reservoir, strong pressure sensitivity, micropore undersaturation, and significant water-lock effect in water injection development lead to increased fluid seepage resistance. There is an urgent need to adopt physical and chemical methods to supplement energy and improve infiltration efficiency, thereby forming effective methods for increasing the production and efficiency. Aiming at the characteristics of ultralow permeability reservoirs, in this paper, a green and environmental friendly biobased profile control and displacement agent (Bio Nano30) has been developed using noncovalent supramolecular interaction. Physical simulation experiments illustrate the profile control and displacement mechanism of Bio-Nano30. Laboratory experiments and field applications show that good results have been achieved in oil well plugging removal, water well pressure reduction and injection increase, and well group profile control and oil displacement. This research has good application prospects in low permeability heterogeneous reservoirs.

Fluid cost saving is critical for fracturing operations in low permeability reservoirs where the production revenues are low but the job size is relatively large and the fluid cost is high. Cross-linked fluids (CLF) are usually the first option. However, they may cause significant damage to both propped fractures and formations, and are not the cheapest option. Polymer-free fluids, on the other hand, cause much less damage but they are expensive and fluid costs may impair the economic results of fracturing. Waterfrac would be a compromise solution for low permeability reservoirs since its fluids are cheap and fluid damage is low. The success of waterfrac with low slurry concentrations is, however, difficult to predict. This paper presents a new fluid system that was formulated to maximize the economic return of fracturing wells in low permeability shallow oil reservoirs. It is a solid-free, linear, synthetic polymer-based system with a very low formation damage characteristic. The new fluid system can meet a variety of fracturing requirements, including slurry concentrations of conventional field levels. Moreover, it is much cheaper than cross-linked guar gel (CLGG). The method for designing fluid components and the procedure for preparing the fluid to achieve minimum formation damage and minimize the cost are described. A comparison of the production performances from the same well or adjacent reference wells fractured with the new fluids and CLGG is made. The reservoir geology, fluid type, and operation data of fracturing, and well performances from more than 300 successful wells in three different low permeability shallow oil reservoirs (800 ∼ 1,500 m depth) are also presented in detail. Introduction Hydraulic fracturing is a necessary technique to develop low permeability reservoirs. Fracturing fluid takes a paramount role in fracturing treatments. In most cases, cross-linked fluids (CLF) can meet the treatment requirements. However, severe formation damage frequently occurred when cross-linked guar gel (CLGG) was used. The core flow tests by Devine et al.(1) showed that the permeability reduction by CLGG was 56% ∼ 71% for cores of 100 ∼ 200 mD, and 12% ∼ 35% for cores of less than 1 mD. The fluid damage to the tight sand was less severe than that of a permeable formation(1, 2). The experiment study by Almond(3) at 120 ° F with 20/40 mesh sand packs (simulating fractures) showed that the flow reduction by CLGG damage could be as high as 100%. Without doubt, damage of this order of magnitude will greatly decrease the productivity of fractured wells, whether the damage happens in formations or in propped fractures. Therefore, fluid impairment by CLGG could be a significant problem adversely influencing the success of fracturing operations. Fluid cost is another critical factor of fracturing, especially in low permeability and tight reservoirs where the job size is large and the fluid cost is high, but the well productivity is low and declines faster than that of fractured wells in conventional reservoirs. Fluid cost saving is a key factor to economically develop these reservoirs, in particular when they are marginal reservoirs.

Low Quality Reservoir in WK Rokan is quite famous as a large volume of remaining recoverable resource, where TLS Formation owned the biggest share (~51%) of the total Low-Quality Reservoir potential additional reserves. This formation develop widely in Central Sumatra Basin with range ~600 ft TVDSS depth and the deepest productive reservoir in ~4000 ft TVDSS. The 600ft TVDSS TLS Reservoir is identified as the most challenging Low-Quality Reservoir in term of its subsurface and operation since this formation has been producing for decades. This Reservoir located in BLSO field in Riau Province, Central Sumatra, Indonesia approximately 140 km Northwest of Pekanbaru or 50 km northwest of the DRI field. The field is a large elongated anticlinal structure bounded on the southwest by a major high-angle reverse fault. The shallowest productive TLS in WK Rokan has a minimum recovery factor with a low reservoir quality which has permeability range of 20-300 MD due to the thin overburden barrier (shallow structure), reservoir complexity (low reservoir permeability, low sand connectivity) that led to limitation of completion strategy resulted in low oil recovery. It is found in 1972, and commercially produced as an oil-producing well with a reservoir depth of 800 - 1000 ft TVD with current recovery factor only 8%. The drive mechanism in this reservoir is shown as a weak water drive reservoir. The old-fashioned development strategy from this shallow low-quality reservoir is by having hydraulic fracturing with cased hole completion which will be driven a high-cost development scenario if we want to increase oil recovery in this reservoir. The alternate solution in developing this shallow reservoir is by optimizing productive section interface, and Open Hole Screen Liner is coming out as solution with lower investment to add more recovery with average production 49 BOPD and low average water cut (51%). This paper will talk about in how we develop well candidacy to apply open hole screen liner completion method, the result and future development plan to improve oil recovery in shallowest low quality reservoir in WK Rokan.

Water plugging and profile control are becoming increasingly important in water-flooding oilfields. In this study, the experiments were conducted to determine the microscopic mechanisms and effects of water plugging, profile control, and ‘water plugging + profile control’. Initially, the starch graft copolymer and polymer gel used showed only slight changes in viscosity. However, within 12 h, the viscosities exceeded 100,000 mPa·s, which indicated that the two agents had good plugging effects. When the plugging agent was starch graft copolymer, the oil recovery with water plugging was 2% and 0.8% higher than the values for profile control with polymer gel on a heterogeneous core and parallel core, respectively. The recoveries with the ‘water plugging + profile control’ combination for the heterogeneous core and parallel core were 25.9% and 25.5%, respectively, which showed the superior enhanced oil recovery. The mechanism research showed that when the reservoir entered the middle and high water-cut development stages, the residual oil was mainly distributed in the middle- and low-permeability layers near the oil well. Thus, water plugging provided a greater increase in oil recovery. Under the actual demands of the Bohai oilfield, it would be better to adopt a combined water plugging and profile control operation.

Flue gas injection into light oil reservoirs could be a cost-effective gas displacement method for enhanced oil recovery, especially in low porosity and low permeability reservoirs. The flue gas could be generated in situ as obtained from the spontaneous ignition of oil when air is injected into a high temp erature reservoir, or injected directly into the reservoir from some surface source. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible or near miscible with the reservoir oil, thereby displacing it more efficiently than an immiscible gas flood. Some successful high pressure air injection (HPAI) projects have been reported in low permeability and low porosity light oil reservoirs. Spontaneous oil ignition was reported in these projects, at least from laboratory experiments; however, the mechanism by which the generated flue gas displaces the oil has not been discussed in clear terms in the literature. An experimental investigation was carried out to study the mechanism by which flue gases displace light oil at a reservoir temperature of 116 °C and typical reservoir pressures ranging from 4,028 psi (27.77 MPa) to 6,680 psi (46.06 MPa). The results showed that the flue gases displaced the oil in a forward contacting process resembling a combined vaporizing and condensing multi-contact gas drive mechanism. The flue gases also became near-miscible with the oil at elevated pressures, an indication that high pressure flue gas (or air) injection is a cost-effective process for enhanced recovery of light oils, compared to rich gas or water injection, with the potential of sequestering greenhouse gases.

Flue gas injection into light oil reservoirs could be a cost-effective gas displacement method for enhanced oil recovery, especially in low porosity and low permeability reservoirs. The flue gas could be generated in situ as obtained from the spontaneous ignition of oil when air is injected into a high temperature reservoir, or injected directly into the reservoir from some surface source. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible or near–miscible with the reservoir oil, thereby displacing it more efficiently than an immiscible gas flood. Some successful high pressure air injection (HPAI) projects have been reported in low permeability and low porosity light oil reservoirs. Spontaneous oil ignition was reported in some of these projects, at least from laboratory experiments; however, the mechanism by which the generated flue gas displaces the oil has not been discussed in clear terms in the literature. An experimental investigation was carried out to study the mechanism by which flue gases displace light oil at a reservoir temperature of 116°C and typical reservoir pressures ranging from 27.63 MPa to 46.06 MPa. The results showed that the flue gases displaced the oil in a forward contacting process resembling a combined vaporizing and condensing multi-contact gas drive mechanism. The flue gases also became near-miscible with the oil at elevated pressures, an indication that high pressure flue gas (or air) injection is a cost-effective process for enhanced recovery of light oils, compared to rich gas or water injection, with the potential of sequestering carbon dioxide, a greenhouse gas.