Higher Oil Recovery Factor Research Articles

Flooding with Biopolymer from Microbes Derived from Mushroom and Cabbage to Enhance Sweep Efficiency in Enhanced Oil Recovery

In this study, local isolated Xanthomonas campestries has been used from local cabbage for xanthan gum production via fermentation in shake flask. The product was then recovered with isopropanol and dried. Meanwhile, for extraction and purification of mushroom polysaccharide, we use dead edible mushroom has been used. Polysaccharide mushroom was extracted with NaOH solutions at 100 ͦ C for 24 hrs. Next, polysaccharide was precipitated separately by the addition of ethanol and the resulting polysaccharide extract were dissolved in distilled water. In the present study, different type of biopolymers was used in order to determine the oil recovery with different concentrations. Biopolymers used in this experiment are xanthan gum and mushroom polysaccharide. The properties of both biopolymers were tested for 3000 ppm and 10000 ppm of concentration. The results shown higher oil recovery factor obtained from the mushroom polysaccharide, which is 84.14%. Meanwhile, the highest recovery obtained by xanthan is about 67.44% only. As a conclusion, increasing polymer concentration will increase the oil recovery factor.

Energy 360: Invited Perspective: Another World’s First From The NCS: Subsea Gas Compression Is Here

President's column Steve Thurston, Chevron’s vice president of deepwater exploration and projects compares developing US Gulf of Mexico oil fields like Jack and St. Malo in 7,000 ft to the 1969 moon landing: “Except we are going to the moon every day!” It really is impressive to see how offshore and subsea technology have evolved over the years. Of the world’s current oil demand of approximately 93 million BOPD, some 27 million BOPD or 30% comes from offshore fields and the offshore contribution is expected to continue to grow according to Douglas-Westwood World Drilling & Production Market Forecast 2005-2021. The Norwegian Continental Shelf (NCS) is among the front-runners in subsea technology developments and applications. It is like a giant “subsea and offshore 2.0 laboratory” for the rest of the offshore world. According to Statoil, it has more than 500 subsea wells and is the world’s largest operator in water depths greater than 100 m. The Troll-Oseberg Gas Injection subsea template installed in 1991 supplies gas subsea from Troll to Oseberg, 48 km away, making a gravity drainage recovery mechanism on Oseberg possible, resulting in a very high oil recovery factor. Through more than 150 multibranched subsea wells (two to six branches per well), individual Troll oil province development wells can connect with nearly 45,000 ft of productive reservoir. Subsea water separation and subsea reinjection units have been successfully used on the Troll oil and Tordis field developments. At the Tyrihans 10% additional recovery is achieved with injection of raw seawater from pumps on the seafloor. Snøhvit and Ormen Lange are all-subsea offshore gas developments and send unprocessed wellstreams to shore 90 and 75 miles from shore, respectively. Efficient subsea gas compression is the next challenge that the industry must face to continue subsea development. When an offshore gas field is developed 100% by a subsea development and the pressure falls because of production, compression will be needed at some point to maintain the production rate. But, there is no platform to put it on—unless you build one. What about installing subsea compression and skipping the platform altogether? Is this even possible? I posed questions to Statoil’s chief engineer in subsea technology, Rune Mode Ramberg, regarding the latest subsea compression developments on the NCS.

Optimization of Miscible CO2 Water-Alternating-Gas Injection in the Bakken Formation

In this paper, optimization of miscible CO2 water-alternating-gas (CO2-WAG) injection in the Bakken formation is experimentally studied. First, tight sandstone reservoir rock samples from the Bakken formation are characterized. Second, the vanishing interfacial tension technique is applied to determine the minimum miscibility pressure of the Bakken light crude oil and CO2 at the actual reservoir temperature. Third, a total of nine coreflood tests are conducted through respective waterflooding, continuous miscible CO2 flooding, and miscible CO2-WAG injection. In the miscible CO2-WAG injection, different WAG slug sizes of 0.125, 0.250, and 0.500 pore volume and different WAG slug ratios of 2:1, 1:1, and 1:2 are used to study their specific effects on the oil recovery factor (RF) in the Bakken formation. In addition, miscible CO2 gas-alternating-water (CO2-GAW) injection is also tested as an opposite fluid injection sequence of the miscible CO2-WAG injection. It is found that, in general, the CO2 enhanced oil recovery method is capable of mobilizing the light crude oil in the Bakken tight core plugs under the miscible conditions. The miscible CO2-WAG injection has the highest oil RF (78.8% in test 3), in comparison with waterflooding (43.2% in test 1), continuous miscible CO2 flooding (63.4% in test 2), and miscible CO2-GAW injection (66.2% in test 8). Furthermore, using a smaller WAG slug size for CO2-WAG injection leads to a higher oil RF. The optimum WAG slug ratio is approximately 1:1 for the Bakken tight formation. More than 60% of the light crude oil is produced in the first two cycles of the miscible CO2-WAG injection. The CO2 consumption in the optimum miscible CO2-WAG injection is much less than that in the continuous miscible CO2 flooding.

Soaking effect on miscible CO2 flooding in a tight sandstone formation

In this paper, the phase behavior and viscosity reduction of CO2-saturated light oil were experimentally studied. The saturation pressures (Psat), gas–oil ratios (GORs), and oil-swelling factors (SFs) of four light oil–CO2 systems with different light oil and CO2 compositions were measured by using a PVT system. The corresponding viscosities of CO2-saturated light oils were measured by using a capillary viscometer. It was found that Psat, GOR, and oil SF were increased respectively in the ranges of 4.97–8.44MPa, 59.0–149.5cm3 CO2/cm3 oil, and 1.14–1.34 when CO2 concentration in the light oil–CO2 system was increased in the range of 38.94–60.46mol.%. Accordingly, the respective viscosities of CO2-saturated light oils with 38.94 and 60.46mol.% CO2 concentrations were reduced to lower than 16% and 10% of the dead light oil viscosity at the same reservoir temperature. Furthermore, a total of six miscible CO2 coreflood tests were conducted to study CO2-soaking effect on miscible CO2 flooding in a tight sandstone formation. It was found that in the coreflood tests without CO2 soaking, a large amount of oil was produced in the first pore volume (PV) of CO2 injection, whereas only a low oil recovery factor (RF) of 0.77–6.10% was obtained in the second PV of CO2 injection. In the coreflood tests with CO2 soaking, the residual light oil and reservoir brine in the composite sandstone reservoir core plugs were soaked with the remaining CO2 for 24h after the first PV of CO2 injection. A high oil RF of 11.05–14.74% was achieved in the second PV of CO2 injection. Among the six CO2 coreflood tests, pre-waterflooding plus CO2 tertiary flooding with CO2 soaking resulted in the highest oil RF, which was attributed to the mobility-control effect of pre-waterflooding and the subsequent CO2-soaking effect.

Aqueous Hybrids of Silica Nanoparticles and Hydrophobically Associating Hydrolyzed Polyacrylamide Used for EOR in High-Temperature and High-Salinity Reservoirs

Water-soluble polymers are known to be used in chemically enhanced oil recovery (EOR) processes, but their applications are limited in high-temperature and high-salinity oil reservoirs because of their inherent poor salt tolerance and weak thermal stability. Hydrophobic association of partially hydrolyzed polyacryamide (HAHPAM) complexed with silica nanoparticles to prepare nano-hybrids is reported in this work. The rheological and enhanced oil recovery (EOR) properties of such hybrids were studied in comparison with HAHPAM under simulated high-temperature and high-salinity oil reservoir conditions (T: 85 °C; total dissolved solids: 32,868 mg∙L−1; [Ca2+] + [Mg2+]: 873 mg∙L−1). It was found that the apparent viscosity and elastic modulus of HAHPAM solutions increased with addition of silica nanoparticles, and HAHPAM/silica hybrids exhibit better shear resistance and long-term thermal stability than HAHPAM in synthetic brine. Moreover, core flooding tests show that HAHPAM/silica hybrid has a higher oil recovery factor than HAHPAM solution.

An Experimental Investigation of Fracture Physical Properties on Heavy Oil Displacement Efficiency during Solvent Flooding

This work is concerned with the role of geometrical properties of fractures on oil displacement efficiency during solvent injection to heavy oil. Here, a series of solvent injection processes were conducted on one-quarter five-spot fractured micromodels that were initially saturated with the heavy oil, at a fixed flow rate condition. The oil recovery was measured using image analysis of the continuously provided pictures. The results show that for the range of experiments performed here, the maximum oil recovery happens at a fracture orientation angle of 45 degrees. Also, increasing the number of fractures leads to a higher oil recovery factor by solvent in 45 degrees, while it does not change significantly for the case of a 90-degree inclination. By increasing the fracture spacing, the oil recovery factor decreased. When fractures are distributed along the mean flow direction, oil recovery is higher than the case where the fractures are more dispersed and are not in the mean flow direction. In the presence of discontinuous fractures, the oil recovery factor decreases in comparison with the case of continuous fractures. The results of this work might be helpful for better understanding the role of fractures during miscible injection processes, which might be used to develop new mathematical models in such a reservoir.

Experimental Investigation of Production Characteristics of the Gravity-Assisted Inert Gas Injection (GAIGI) Process for Recovery of Waterflood Residual Oil: Effects of Wettability Heterogeneity

The impact of reservoir heterogeneities in terms of wettability at the macroscopic scale on the recovery efficiency of the gravity-assisted inert gas injection (GAIGI) process was investigated through a systematic experimental study for tertiary recovery of waterflood residual oil. Isolated inclusions of oil-wet consolidated glass beads were embedded in a continuum of unconsolidated water-wet glass beads to create heterogeneous packed columns. In comparison to water-wet homogeneous porous media, such heterogeneous media allowed us to establish higher waterflood residual oil saturation whose amount varied linearly with the volume fraction of oil-wet heterogeneities in the packing. Experimental results obtained from tertiary gravity drainage experiments demonstrated that the continuity of water-wet portions of the heterogeneous porous medium facilitates the tertiary oil recovery through the film flow mechanism, provided that the oil-spreading coefficient is positive. In addition, owing to the high waterflood residual oil content of the heterogeneous media tested, the oil bank formation occurred much earlier and grew faster, resulting in a higher oil recovery factor. However, having favorable wettability conditions in homogeneous porous media resulted in slightly lower reduced residual oil saturation after the GAIGI process compared to that in the heterogeneous media with the same condition of withdrawal rate. A relationship between the oil recovery factor at gas breakthrough and gravity number was developed for the heterogeneous and homogeneous media. The recovery factor at gas breakthrough versus gravity number in homogeneous media follows a similar trend as that of homogeneous water-wet porous media. However, at a given gravity number, the recovery factor of heterogeneous media was greater than that of the homogeneous media.

Optimum phase type and optimum salinity profile in surfactant flooding

According to the conventional concepts in surfactant flooding, a type III microemulsion phase environment would give higher oil recovery than either a type II(−) or a type II(+) environment, and a negative salinity gradient is a preferred gradient which provides the highest oil recovery factor. However, principles and some measured data suggest that these concepts should not be valid universally.In this paper we investigate the effects of microemulsion phase type and salinity profile on oil recovery quantitatively by using a chemical flood simulator, UTCHEM (2000). Over 200 simulation cases covering a variety of flow conditions have been run. The simulation results clearly demonstrate that the two conventional concepts cannot be valid universally. We discuss the salinity gradient effect based on the principles of multiphase flow. In surfactant flooding, many parameters can affect oil recovery, especially multiphase flow parameters.In this paper we propose two new concepts. One is the optimum microemulsion phase type which is not necessarily type III. Another one is the optimum salinity profile which has the following characteristics:1.The optimum salinity is within the optimum phase type which corresponds to the highest oil recovery, not necessarily within type III.2.The optimum salinity must be used in the surfactant slug.3.Two guard slugs with the same optimum salinity are placed immediately before and after the surfactant slug. But the optimum salinity in the guard slug before the surfactant–polymer slug is preferred but not mandatory.4.The salinity in the post-flush must be below the lower salinity bound of type III.Our simulation results show that the optimum salinity profile can always lead to the highest recovery, especially higher than that from the corresponding negative salinity gradient. Extensive literature information and laboratory data are used to support these new concepts. These concepts can be used to design an optimized field surfactant flooding program.

In Situ Upgrading of Athabasca Tar Sand Bitumen Using Thai

Downhole upgrading of virgin Athabasca Tar Sand bitumen has been investigated in a series of 3-D experiments using THAI—‘Toe-to-Heel Air Injection’. The THAI process uses combinations of vertical injection wells and horizontal producer wells, arranged in a direct, or staggered line drive. 3-D experiments were performed to investigate THAI as a primary recovery method, and also as a secondary recovery method. The latter followed a prior THSF—‘Toe-to-Heel Steam Flood’. Oil recovery efficiencies for THAI, using primary and secondary operation modes, were respectively, 80% and 67% OOIP. The THSF recovery was much lower, only 23% OOIP, owing to the low steam temperature in the sandpack. Downhole upgrading of the Athabasca Tar Sand bitumen was very significant, with the API gravity of the produced oil increasing by an average of 8° API, compared to the original bitumen. The produced oil viscosity was also dramatically reduced, to less than 200 mPa s, with a minimum value of 50 mPa s. SARA analysis was used to assess the quality of the produced oil. The original bitumen contained only 15.5% saturates, but the amount in the produced oil was increased to 72%. The high oil recovery factor and partial in situ upgrading achieved by the THAI process could therefore have important economic implications for the future of heavy oil and bitumen production. The first field pilot of the THAI process is scheduled to take place at Christina Lake, Alberta, Canada, in 2006.

Network Modelling of Apparent-Relative Permeability of Gas in Heavy Oils

Abstract Some of the solution-gas drive heavy oil reservoirs known as foamy oil reservoirs, in Canada, Venezuela, and other countries have demonstrated a high primary oil recovery factor (>10%), a low producing gas-oil ratio, a low reservoir pressure decline, and a high oil production rate. One of the hypotheses to explain these unusual behaviours is that the gas mobility in a foamy oil flow is much lower than that in conventional oil, leading to improved recovery performance. In this study, the immiscible two-phase micro-displacement in porous media is modelled by using a network of pores of converging-diverging geometry. The effect of viscosity of one phase (oil) on the mobility of another phase (gas) is included in the model. The developed model is used to simulate the motion of the dispersed bubbles in an initially oil-filled network, and to determine bubble mobility. The obtained results showed that bubble mobility decreased drastically by increasing the oil viscosity. The results also showed that dispersion of gas leads to lower mobility of bubbles. Dispersed gas flow and low bubble mobility are believed to lead to improved recovery in foamy oil reservoirs. Introduction Some of the solution-gas drive heavy oil reservoirs in Canada, Venezuela, China, and Oman have demonstrated unusually high primary production rates, high primary oil recovery factors (>10%), low producing gas-oil ratios, and low reservoir pressure declines(1, 2). To explain these unusual behaviours, three fundamental reasons have been suggested: geomechanical effects(3), special fluid properties(4), and unusual flow dependent properties of oil and gas(5). Most researchers now believe that the low mobility of gas is the main reason for low producing GOR and high recoveries obtained(1, 2). Gas mobility in a heavy oil system is investigated in this paper. In one study, solution-gas drive experiments were performed in an identical sand-pack, using light oil and heavy oil(5). The experimental studies clearly showed that gas mobility in the two experiments differed by about four orders of magnitude. It has been observed that matching of field(6) and laboratory depletion data(5) required assigning extremely low values of gas relative permeability. The relative permeability functions of these studies, however, were obtained through history matching. Of primary interest is, how can relative permeability functions be determined for a particular system a priori? Following this question, the first step is to find what parameters affect relative permeability functions; the second is to find how these factors are ranked in their importance. These steps are investigated in this paper. A microscopic scale (network) model is developed and used to investigate the effects of different parameters, in particular, oil viscosity on gas mobility in porous media. Network models are simplified mathematical representations of real porous material. The objective of a porous network model is to provide a reasonable idealization of the complex geometry of a real porous medium on a microscopic scale, so that the related fluid flow can be treated mathematically at a manageable level of complexity.