Koorosh Asghari

IN SITU COMBUSTION IN ENHANCED OIL RECOVERY (EOR): A REVIEW

Enhanced oil recovery (EOR) refers to the technologies developed to increase extraction of crude oil from reservoirs after primary production. In situ combustion (ISC) is one of the methods developed for EOR. This review examines studies done by researchers worldwide to improve our understanding of the mechanism of oil cracking kinetics, which is one of the fundamental mechanisms of in situ combustion. Good agreement between the laboratory and field results has encouraged further research in this field. Extensive research at the laboratory scale to understand the pyrolysis and oxidation behavior of coke formed from medium and light oil and also to propose more realistic models to mimic the true behavior of in situ combustion has been undertaken in recent years. Apart from the classical Arrhenius model, researchers have come up with other models (two-step oxidation model) based on the type of combustion activity observed from their samples, thus modeling the process more accurately. Research work showing optimization of the parameters of ISC and improving the economic viability of the entire process is been one of the main focuses of this article. The review also explains the nature of the various experiments, sheds light on some of the concepts that remain unexplained, and opens the way for fresh thinking in those areas. It also highlights the possibility of developing global solutions for numerical simulation of this EOR process.

Application of CO-Foam as a Means of Reducing Carbon Dioxide Mobility

Reducing the mobility of carbon dioxide through co-injection of CO 2 and a suitable surfactant solution to form a CO 2 -foam system is a promising method for improving the oil recovery in carbon dioxide flooding projects. This paper presents the results of a set of experiments on screening and selecting a suitable surfactant for CO 2 -foam purposes in a carbonate porous medium, as well as the effect of various parameters on the mobility of the CO 2 -foam system. Four surfactants were examined and the one that performed best throughout the screening experiments was used in the subsequent flow experiments. The surfactants tested were Surfonic N-95, Surfonic L24-9, Bio-Terge AS-40, and Chaser CD-1045. The screening criterion selected was the fall in foam height with time at 60° C for 0.1 wt% solution of the above mentioned surfactants. Chaser CD-1045 performed best in all screening tests and was used during the flow experiments. Flow experiments were conducted through a porous medium made of crushed carbonate at pressures of 8,270 kPa and 10,336 kPa, and temperatures of 22° C and 50° C. Mobility of CO 2 -brine (simulating the WAG process) and CO 2 -surfactant systems were compared through a series of experiments. The effect of operating pressure and temperature, brine concentration, and the ratio of the amount of CO 2 to total foam (i.e., foam quality) on the mobility of a CO 2 -foam system were investigated and results are presented. The results indicate that additional oil is recoverable for CO 2 -foam vs. the co-injection of CO 2 and brine simulating the WAG process.

Optimization of carbon dioxide sequestration and improved oil recovery in oil reservoirs

Publisher Summary The vast majority of industrialized countries, irrespective of their position regarding the Kyoto Protocol, have started to take actions toward reducing the emission of carbon dioxide (CO2) and other gases, such as methane (CH4) and nitrous oxide (N20), into the atmosphere. However, application of CO2 storage or enhanced oil recovery (EOR) in carbonate reservoirs is more challenging due to their extreme heterogeneity of both porosity and permeability. Past injection/production practices, aquifer strength, reservoir heterogeneity, and CO2 injection schemes, such as injecting CO2 at the top or bottom of the reservoir or using horizontal wells instead of vertical wells for injection and production purposes are among the main factors affecting both oil recovery and CO2 storage capacity. It discusses the effects of different injection schemes and the timing of injection on optimization of oil recovery/CO2 storage capacity for a partially depleted oil reservoir.

Improving Gel Performance in Fractures: Chromium Pre-Flush and Overload

High water cuts during waterflood operations are a major problem encountered in mature reservoirs. Areas of the reservoir that are fractured, either naturally or hydraulically, are excellent pathways for floodwater to bypass oil-bearing pore spaces. Gel placement within fractured zones of the reservoir is a technique that has been employed to decrease water production. In order to utilize this technique more effectively, the improvement of gel placement and its performance within fractures must be investigated. For the purposes of this study, two experimental setups are developed. Initially an acrylic fracture model is developed in order to obtain qualitative information about flood fluid penetration into the placed gel. The rupture pressure of the HPAM-Cr (III) [hydrolyzed polyacrylamide-chromium (III) acetate] gel system is observed for 1x, 2x and 3x gel systems (multiplier refers to chromium concentration) within the fractures. The rupture pressures observed are generally higher for gel systems with greater chromium concentration. The acrylic setup also allows for visual observation of the gels performance and behaviour during water injection. Water penetration is dominated by one major channel. Smaller channels are often observed to either branch off from the dominant channel or smaller side channels would connect and join the flow path of the major channel. Secondly, Berea sandstone slabs are cut and an experimental setup is built in order to study two main mechanisms for improved gel placement. The application of Cr (III) acetate pre-flush and overload are investigated in order to determine their effect on gel performance within fractures. Both techniques compensate for the amount of chromium lost to the matrix via molecular diffusion and the integrity of the gel is maintained. This allows for significant fracture blockage without having to place performed gel or placing the gelant with leak-off in order to achieve a stable gel.

Effect of Connate Water Saturation, Oil Viscosity and Matrix Permeability on Rate of Gravity Drainage During Immiscible and Miscible Displacement Tests in Matrix-Fracture Experimental Model

Miscible injection of carbon dioxide has seen a significant increase in interest for the purpose of enhanced oil recovery (EOR) in conventional oil reservoirs. However, naturally fractured reservoirs, which are among the largest oil reserves in the world, are considered poor candidates for this process because of presumed low-performance efficiency. This paper presents the results of an experimental study that explains the effect of connate water saturation, matrix permeability and oil viscosity on the performance of gravity drainage from the matrix (into fracture) when it is surrounded by a CO 2 -filled fracture. Experiments were performed in an experimental model under different operating pressures to cover both immiscible and miscible conditions. Experiments were conducted using synthetic oil (nC 10 ) and light crude oil in two Berea cores having large differences in permeability. In addition, the effect of connate water saturation was studied by performing experiments in an initially brine-saturated Berea core and comparing the results with those obtained when the core was 100% saturated with oil. The experimental results showed that matrix permeability had a significant effect on the rate of gravity drainage when CO 2 was injected under immiscible conditions. When experiments were performed at immiscible conditions, production rate by gravity drainage was nearly five times greater in the Berea core with 1,000 md permeability compared to the core permeability of 100 md. The production rates in the cores investigated were similar at low pressures (below 3,400 kPa), but slightly higher for the higher-permeability core. As system pressure was increased beyond 3,400 kPa, the production rate from the higher-permeability core increased significantly, compared to the lower-permeability case. Beyond miscibility conditions (~6,900 kPa), matrix permeability was less significant, indicating the important role of capillary pressure in the gravity drainage mechanism. However, ultimate oil recovery was less sensitive to the matrix permeability at pressures near or above minimum miscibility pressure. The observations were more interesting when experiments were performed in the presence of connate water saturation. The ultimate oil recovery from a core saturated with oil in the presence of connate water saturation was less at immiscible conditions. However, at near-miscible and miscible conditions, the presence of connate water was beneficial to the gravity drainage mechanism in that it led to higher ultimate oil recovery. The effect of oil viscosity appeared to be important during the sustained miscibility of CO 2 and hydrocarbon phases. For the crude oil examined, the heavier components that remain in the oil phase after the vapourizing gas drive limited the length of the oil production period when compared with the nC 10 production. Miscible CO 2 injection in fractured reservoirs is a viable option for both oil recovery and storage purposes because as the residual oil saturation is reduced, additional pore volume (PV) becomes available to store CO 2 in its supercritical form. However, under immiscible conditions, when CO 2 is injected at pressures below the minimum miscibility pressure (MMP) and above the supercritical condition, it is not beneficial for improving oil recovery by gravity drainage. This was clearly seen when gravity drainage experiments using crude oil were performed and MMP was not achieved at the maximum possible operating pressures.

Water permeability reduction under flow-induced polymer adsorption

The influence of induced polymer adsorption for reducing the effective permeability to water in reservoirs is investigated. Previous studies on polymer adsorption in porous media have shown that a static adsorption regime exists at low shear rates of injection. This results in a thin polymer layer whose capability to reduce water permeability is marginal. However, polymer injection at increasing shear rates has revealed an increase in the adsorbed polymer layer and, consequently, improved water permeability reduction. Here, results from sandpacks are presented to show that at increased shear rates, there is improvement in the adsorbed polymer layer. This phenomenon is known as flow-induced adsorption. The experiments indicate that above a critical shear rate, there is a shift in the permeability-reduction mechanism from static to flow-induced adsorption, necessitating a sharp increase in the adsorbed polymer layer. All results revealed that the critical shear rate for this polymer is about 300 s -1 in the absence of mechanical degradation. This critical shear rate defines the optimal rate of polymer injection for better economic viability of the process. The findings of this study improve the current understanding of the mechanisms involved during polymer squeeze operations and therefore will assist in developing better injection processes with improved chances for success.

Application of In-Depth Gel Placement for Water and Carbon Dioxide Conformance Control in Carbonate Porous Media

This paper presents the results of an investigation of the application of gel placement in an attempt to reduce the effective permeability of a carbonate porous medium to water and supercritical carbon dioxide, as encountered in the CO 2 flooding of carbonate reservoirs. Three gel systems based on a high and a low molecular weight polyacrylamide polymer with chromium(lll), as crosslinker, were used for this study. Since sodium lactate is commonly used for increasing gelation time at elevated temperatures, experiments were conducted by adding sodium lactate to the gel solution with a ratio of polymer to sodium lactate equal to one. The higher molecular weight polyacrylamide gel system was composed of 7,200 ppm Alcoflood 935 and 300 ppm Cr(III), while the other gel system tested was composed of 5% low molecular weight polyacrylamide (Alcoflood 254S) with a ratio of 1:12 chromium(III)-acetate to polymer as crosslinker. Experiments were conducted at 8,274 KPa and 40° C with and without the presence of residual oil. Performance and stability of the above gel systems for reducing the permeability of the carbonate medium to the injected water and carbon dioxide was tested in a series of flow experiments by alternately injecting several pore volumes of water and carbon dioxide into the porous media in several cycles. The porous medium used was crushed carbonate with an initial permeability of over 9.86 μm 2 . For all experiments, the presence of S or led to lower residual resistance factors (RRF). Nevertheless, RRFs were between 100 and a few thousands for all experiments conducted. The results obtained are a clear indication of the effectiveness of these gel systems for conformance control purposes during carbon dioxide flooding projects in carbonate reservoirs.

Underground ultrasound probing for monitoring carbon dioxide flooding in oil producing reservoirs

The problem of identifying the position and location of immiscible or miscible layers is a critical issue in methods of carbon dioxide injection for oil producing bodies. Accurate knowledge of the position could lead to an ability to control the position of the carbon dioxide front affecting production, efficiency, economy, and, in the end, profitability. The approach of studying the progress of carbon dioxide in reservoirs using ultrasound is new and may lead to unique and powerful ways of monitoring the position of carbon dioxide, as well as visualizing the reality of the oil producing area. Firstly in this paper, some basic experiments to investigate the acoustic properties in many situations are described. These experiments include the ultrasound reflection properties of stationary water-air, water-oil, air-oil, oil-oil interfaces, as well as those of moving interfaces. Secondly, experiments of ultrasound reflection properties in porous mediums combined with air, water and oil are described. These experiments include reflection of air-water interfaces in porous mediums, oil-water interfaces in porous mediums, and air-oil interfaces in porous mediums. Thirdly, measures of digital signal processing are introduced to obtain position information of interfaces in porous mediums and improve the resolution and accuracy of the location. Ultrasound has many advantages as a tool in underground probing, such as small size, low power consumption and safety.

Operation Parameters on CO2-Foam process

Abstract Reducing the mobility of CO2 by means of generating in situ foam is an effective method for improving the oil recovery in CO2 flooding processes. Implementation of the CO2-foam technique typically involves the co-injection of CO2 and surfactant solution into the porous medium. The surfactant molecules form bubble films that trap the flowing CO2 molecules. The effectiveness of the CO2-foam process is measured in terms of foam mobility. The mobility of CO2-foam is affected by different operation parameters, such as pressure, temperature, foam quality, and brine concentration. However, surfactant type governs the overall efficiency of the CO2-foam process. This paper presents the results of a series of experiments conducted to study the effect of various parameters on the CO2-foam process. Bottle tests were conducted for four commercially available surfactants and among them, Chaser CD-1045 was found to be the most effective surfactant for CO2-foam flow under reservoir conditions. It was observed that an increase in pressure from 1, 200 psi to 1, 500 psi leads to increase of the mobility of CO2-foam, and an increase in temperature from 72 to 122°F reduces the mobility. Also, as the foam quality increases from 20 to 80%, the mobility decreases. It was observed that there was no significant effect on the mobility with an increase in brine concentration from 1 to 3 wt%.

PERFORMANCE AND PROPERTIES OF KUSP1–BORIC ACID GEL SYSTEM FOR PERMEABILITY MODIFICATION PURPOSES

ABSTRACT Blocking high permeability zones of reservoirs by hydrogels, and diverting the injected fluid towards the unswept zones of the reservoir is a promising method for improving the overall oil recovery in waterflooding and carbon dioxide flooding processes. A polymer gel treatment typically involves the injection of a solution of a medium to high molecular weight polymer and crosslinking agents into the high permeability zones or fractures. The polymer reacts with the crosslinker to form a three-dimensional gel network. KUSP1 biopolymer in sodium hydroxide solution produces a delayed gel system with orthoboric acid. The gelation time varies depending on the concentration of the orthoboric acid and temperature. Syneresis of this gel was studied in bottle tests as well as in the porous media. Samples of KUSP1–boric acid gel lost more than 80% of their initial volume in bottle tests after 250 h. Also, it was observed that this gel, when placed in a sandpack, lost up to about 50% of its initial volume. However, the high values of syneresis did not have a severe effect on the performance of the gel in porous media. KUSP1–boric acid gel was tested for reducing permeability to carbon dioxide and water in a series of tests conducted in a Berea sandstone core. It reduced the carbon dioxide permeability from 164 to 26 md and brine permeability from 420 to 90 md.