Farshid Torabi

The evaluation of CO2-based vapour extraction (VAPEX) process for heavy-oil recovery

Vapor extraction (VAPEX) has been proposed as an alternative for heavy-oil recovery in reservoirs where thermal methods face technical and economic problems. In VAPEX, a pair of horizontal injector-producer wells is employed. The gaseous hydrocarbon solvent (normally propane or a mixture of methane–propane or propane–butane) is injected from the top well and the diluted oil drains downward by gravity to the bottom producer. Recently, the idea of incorporation of CO2 into the gaseous hydrocarbon mixture has emerged. Incorporation of CO2 is believed to make the process more economical and environmentally and technically attractive. CO2 is cheaper than the hydrocarbon gases and has higher solubility into the heavy oil than most of the hydrocarbon gases. It also adds value to the environmental side of the process as CO2 can be sequestered while improving the VAPEX performance at the same time. Moreover, the addition of CO2 to the injected gas increases the dew point of the solvent mixture, and solvent mixtures with higher dew point can be used in heavy-oil reservoirs with higher pressure in which the mixture of hydrocarbon gases may partly condense, which decreases the VAPEX efficacy. Thus, the advantage of incorporating CO2 into the injected solvent is threefold. The objective of this work, therefore, is to simulate the performance of the VAPEX process when different solvent mixtures, including hydrocarbon gases and CO2, are incorporated with the aim of improving its performance. The design and the major results of the simulation for the CO2-based VAPEX process are discussed.

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.

Analysis and Correlations of Viscous Fingering in Low-Tension Polymer Flooding in Heavy Oil Reservoirs

Low-tension polymer flooding (LTPF) can be an alternative for improving the recovery from some problematic heavy oil reservoirs, especially thin formations, where thermal methods face some challeng...

Experimental investigation of the extent to which different concentrations of C3H8, CH4 and CO2 affect CSI performance

T prolific Niger Delta basin is a mature petroleum province. Therefore, further prospectivity in the basin lies within deeper plays which are high pressure and high temperature (HPHT) targets. One of the main characteristics of the Niger Delta is its unique diachronous tripartite stratigraphy. Its gross onshore and shallow offshore lithostratigraphy consists of the deep-seated Akata Formation and is virtually exclusively shale, the petroliferous paralic Agbada Formation in which sand/shale proportion systematically increases upward and at the top, the Benin Formation composed almost exclusively of sand. This stratigraphic pattern is not exactly replicated in the deep offshore part of the delta. The downward increasing shale percentage in the older and deeper parts of the basin poses a great problem to drilling. Increasing shaliness usually leads to wellbore instability and such other problems as pack-offs and stuck pipe. These hazards are the main causes of non-productive time in expensive deep-water or high temperature and high pressure (HPHT) drilling operations. Moreover clay mineral diagenesis generates mixed layer clays at higher temperatures and this tends to cause overpressures that may lead to disastrous kicks, losses and even blowouts. Predicting and managing drilling in such over-pressured or problem sections will form a major part of the evaluation for exploration and development in these parts of the delta. A formation sensitivity test consisting of the detailed study of the influence of various ions on the degree of formation damage of one of the main producing fields in the eastern Niger Delta has been studied. Analytical results of clay mineral composition obtained using X-ray diffraction (XRD) methodology were successfully applied to predict the various types of clay minerals present and hence intervals problem of shales. Further experimental formulations derived using Capillary Suction Time (CST) tests found that addition of 7% KCl to the original water based drilling fluid made drilling through the problem sequences easier leading to very good cost savings and compliance with the Nigerian environmental regulations. The operator has planned deeper drilling and further development of the field.Introduction and objectives Due to the increase in oil price and its cumulative usage, enhanced oil recovery (EOR) processes have been introduced worldwide in the last two decades. The capillary and viscous forces lead to oil recovery using the primary and secondary recovery processes, and the remaining trapped part of oil is produced. Since the new technologies emerged in oil industry for viscous oil recovery, the perspective of the world’s oil provision has been changed. Cyclic Steam Stimulation (CSS) is a thermal recovery method which is applied for heavy oil reservoirs. Other techniques include, in-Situ Combustion (ISC), Steam Assisted Gravity Drainage (SAGD), and Continuous Steam Injection ].Steam Assisted Gravity Drainage (SAGD) is one of the common thermal processes in which a pair of horizontal wells is drilled. This process was later modified to reach to higher efficiency values by introducing Fast SAGD, and NCG’s SAGD processes. In Fast-SAGD process, the system is equipped with offset wells using cyclic steam stimulation to increase the rate of growing the chamber sideway. The CSS process then begins at higher pressures in respect to SAGD wells. Following this approach, the steam chamber is grown laterally. In the present study, the effect of operating parameters including CSS well elevation, CSS well injection pressure and rate, CSS well starting time, spacing of SAGD wells and SAGD wells injection rate are studied on oil recovery factor. The optimum operating conditions is obtained using the CSOR and net present value (NPV) as the goal function.

Performance of immiscible and miscible CO2 injection process in a tight carbonate reservoir (experimental and simulation approach)

In this study, the technical feasibility of CO2 injection in a core sample of a tight carbonate reservoir was investigated under various operating conditions. First, the minimum miscibility pressure (MMP) of CO2/oil system was determined to be 1,907 Psia. The effects of the operating pressure as well as the injection flow rate of CO2 on the oil recovery were examined. The results showed that at the operating pressures far below the MMP, the ultimate oil recovery factor is considerably low and increases as the pressure approaches near-miscible condition. When injection pressure was increased to 2,000 Psia, the ultimate oil recovery factor reached 0.81 and further increase in injection pressure did not significantly improve the recovery factor. For injection pressures lower than MMP (i.e., immiscible condition), increasing injection flow rate of CO2 resulted in lower oil recovery, while at the pressures near and above the MMP, the ultimate oil recovery was much less dependent on CO2 injection flow rate. All the test results were simulated using the CMG package, ver. 2011 and attempt was made to history match the experimental results. In this process, relative permeability curves were used as matching parameter. The simulation results were in good agreement with experimental values. [Received: March 12, 2013; Accepted: August 4, 2013]

The Relationship Between the Productivity Index and the Diffusivity Coefficient and Its Application in Reservoir Characterization

Abstract The authors offer a reliable means to determine the diffusivity coefficient and permeability distribution throughout a reservoir while minimizing the number of expensive well tests. To explain this inexpensive procedure, data of the Asmari Reservoir—located in Iran on the Coast of Persian Gulf—are used. Using well test, petrophysical, pressure-volume-temperature, and production data, a relationship between the productivity index and the diffusivity coefficient is established for the Asmari Reservoir without relying on the reservoir radius value, which is uncertain when obtained from drawdown well testing. This method determines the optimum locations for new wells in development of giant fields.