The Vapor Extraction (Vapex) process and its many hybrid variants have attracted a great deal of attention as potentially less energy intensive alternatives for exploiting heavy oil and bitumen resources. However, despite much work over the past two decades, uncertainty remains about the basic mechanisms, the scaling aspects and the most appropriate methods of numerically simulating these processes. This paper offers some insights into several of these outstanding questions. The questions are examined in the context of an extensive and well-documented set of Vapex experiments carried out by Maini and his colleagues over the past 10 years.
We have experimented with different methods of simulating these experiments using a physics-based reservoir simulator. Despite the high permeability (greater than 200 Darcys in all of the experiments), we find that capillary pressure plays a significant role in the drainage. The simulations suggest that most of the drainage takes place in the capillary transition zone along the edge of the vapor chamber, rather than in the single-phase zone ahead of it which has not yet been contacted by vapor.
It has been emphasized in the literature that the near-linear scaling of oil rate with height observed in the experiments is dramatically different from the square root of height dependence predicted by the original analytic model of Vapex. However, the experiments also show an increasing solvent fraction in the produced oil phase as height increases. When this "solvent mixing?? effect is separated out of the rates, the remaining height dependence is less than linear, though still greater than square root of height.
The relative roles of molecular diffusion and mechanical dispersion in Vapex have been widely discussed in the literature. Generally, mechanical dispersion is expected to play a larger role in these high permeability experiments (vis-à-vis the field), due to larger fluid velocities. We present a method of inferring the diffusion/dispersion present in the simulations, despite a hidden component of numerical dispersion caused by the numerical method itself. We find that the experiments are well matched with values of diffusion and dispersion in line with literature correlations, and that the contribution of mechanical dispersion is perhaps not as large relative to that of molecular diffusion as might be expected.
The paper also provides some thoughts on questions we believe are still unanswered, including mechanisms behind the height dependent mixing phenomenon and the scaling of the experimental results to the much greater heights and lower permeabilities characteristic of the field.
Sand production in a perforated sample is determined by the onset of a significant discrepancy between strains in two orthogonal directions. The onset is also analyzed by three different sanding models, i.e., shear failure, cohesive tensile failure, and the effective plastic strain (EPS) models, respectively. Comparing these results, we conclude that the results with the shear failure criterion provide the most conservative prediction, and the EPS can provide the closest results to the testing one, given adequate plastic yielding and sanding parameters. Comparing with the cylindrical cases (open hole), both the plastic radius and critical strains calculated for the perforated cavity (cased hole) cases are calculated. A critical equivalent plastic displacement (EPD) is proposed as only one additional parameter is required on top of those from a typical elastoplastic model and such a criterion allows us to determine the sanding onset directly, those using stress, strength or strain whereas can only be indicated or interpreted indirectly, yet difficult to measure in practices.
Sahin, Secaeddin (Turkish Petroleum Corp) | Kalfa, Ulker (Turkish Petroleum Corp.) | Celebioglu, Demet (Turkish Petroleum Corp.) | Duygu, Ersan (Turkish Petroleum Corp.) | Lahna, Hakki (Turkish Petroleum Corp.)
The Bati Raman field is the largest oil field in Turkey containing approximately 1.85 billion barrels of initial oil in place at an average depth of 4300 ft. The oil is heavy (12o API) with high viscosity and low solution gas. Primary recovery between 1961 and 1986 was less than 2% of OOIP.
The commercial CO2-EOR project began in 1986 and is still active. With the implementation of the CO2 flood, the recovery is expected to potentially reach up to 10% of OOIP.
The reservoir rock is naturally fractured carbonate where the heterogeneities and the unfavorable mobility ratio of CO2 and crude caused inefficient sweep. The solubility of CO2 in the oil, which is highly sensitive to reservoir operating pressure, was a significant factor for the success of the CO2 flood. Currently, the injected agent is increasingly bypassing the remaining oil and the production is curtailed by excessive high gas/oil ratio (GOR) severely jeopardizing recovery. These conditions prompted the use of applications of the conformance-improvement systems in the wells in western part of the field.
Successful applications of fracture plugging polymer gel system intended for the conformance improvement were carried out in the years of 2002 and 2004. Also, to improve the recovery by a better sweep (or displacement), a chemically augmented water injection process was proposed in the areas having relatively lower reservoir pressure. Chemicals were tested for wettability alteration and IFT reduction to select the best performing ones. After an economic analysis, a field trial of the water alternating gas (WAG) injection process with caustic was put into progress in 2010.
Optimized application cases were determined by tuning the total gas injection rates of the field, proration of the individual well rates according to the GOR, investigation of infill drilling, and alteration of the gas injection pattern, based on the results of the simulations carried out in different time frames of the project history.
The Bati Raman immiscible CO2 injection project has been acknowledged as one of the most unique and successful enhanced oil recovery (EOR) applications in the history of fractured heavy-oil carbonate reservoirs. This paper presents a comprehensive overview of this project after a quarter century of experience.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Heavy Oil Conference Canada held in Calgary, Alberta, Canada, 12-14 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract In Situ Combustion, ISC, is a process with strong potential to compliment Steam Assisted Gravity Drainage by extending the economic life of the SAGD pattern and hence improving the ultimate recovery. Implementing In-Situ Combustion, as a followup process to SAGD can improve recovery from the pattern by displacing residual oil from the steam chamber and more importantly by recovering oil from the wedge zones.
Ren, Fangxiang (CNPC) | Sun, Yan (Liaohe Oilfield, PetroChina) | Yu, Tian Zhong (Liaohe Oilfield, PetroChina) | Fan, Hong Zhao (Liaohe Oilfield, PetroChina) | Lv, Jian Yun (Liaohe Oilfield, PetroChina) | Nie, Xiangbin (RC 2) | Song, Ju (Schlumberger) | Wang, Ruo (Schlumberger) | Zou, Mi (Schlumberger S A) | Niu, Yuqiang (Schlumberger) | Yang, Bin
More than 50% of the heavy oil resources for PetroChina Liaohe exist in thin (approximately 3- to 8-m thick) reservoirs. For this type of reservoir, steamflooding with conventional vertical wells is not economically profitable, and in-situ combustion methods are not applied because of operational difficulties. Horizontal well technology brought a new direction to attempts to improve technical and economic performance of steamflood operations. Many experiments had been conducted to use the technology in the Liaohe oil field to achieve economic production, but the expected results were still not achieved. Lessons learnt indicate that the root cause is the poor oil contact of the horizontal wells' trajectories in the thin, heavy oil reservoir. A pilot project was conducted to explore whether horizontal well technology in combination with optimized cyclic steam stimulation could deliver economic production from these thin heavy oil reservoirs. Horizontal well placement was accomplished by using near-bit azimuthal measurements and images.
Both the feasibility and economic performance of the technology have been studied in this five-well pilot project. Comparing the performance of these five wells to the previous ones, the results indicate that
1) The well-placement drilling solution can maximize the oil contact up to an average 91% of net-to-gross coverage.
2) The well-placement drilling solution improved drilling efficiency by 40%.
3) The drilling operation was conducted with no nonproductive time (NPT), compared to the previous NPT maximum of 6 days.
4) The well-placement drilling solution did keep the cost flat, and the cost even slightly declined.
5) The optimized cyclic steam stimulation in well-placement-drilled wells can decrease the cyclic steam stimulation cost over production to 1000 RMB/ton, which is recognized as an economic ideal in the industry.
6) The daily block production has increased from 20 tons/day to 72 tons/day after using the combined well-placement-drilling and cyclic steam stimulation technology, which is an increase of 210%.
7) The income/input ratios at the end of the fourth year for the two better wells are both 1.48 (reaching a balance at the second and third years, respectively), and ratios for all five wells ratios averaged 0.93, which means the wells will earn net money at the beginning of the fifth year. Compared to the ratio of 0.03 for a previously drilled well, this is not only a big financial improvement, but is also an incentive to revitalize many similar thin heavy oil reservoirs because it proves the possibility of developing them within the economic margin.
The success of the pilot project proved to us that horizontal well-placement drilling in combination with optimized cyclic steam stimulation is an effective way to develop thin-layered heavy oil reservoirs within the economic margin in Liaohe oil field. We extended this horizontal well technology to other blocks and have achieved repeated success.
The most important parameters in the calculation of the rate and extent of gas dissolution during solvent-based heavy oil recovery processes are diffusion coefficient and solubility. However, there is a lack of sufficient experimental data on these parameters. Further, significant differences associated with reported values of diffusivities because of various nonphysical approximations made in development of the models used for calculation of this coefficient from the pressure-decay tests.
This paper presents an inverse solution technique for determining solubility, diffusion coefficient and interface mass transfer coefficient of gases in liquids (bitumens) using pressure-decay data. The approach, which is based on modeling the rate of pressure decline in response to gas diffusion, couples gas mass balance equation with the diffusion equation. Analytical solution for the forward problem is obtained by assigning physically meaningful initial and boundary conditions. Then, the forward solution is utilized to develop an interpretation technique for simultaneous determination of the equilibrium solubility, diffusivity and interface mass transfer coefficient of gas into oil. To evaluate the validity of the proposed technique, literature pressure-decay data of CH4 and CO2 dissolution in Athabasca bitumen at two different temperatures (50 and 90 °C) and initial pressure of 8 MPa were used. The simultaneous estimation of the three mass transfer parameters is the main advantage of the new methodology over the existing ones. Additionally, the calculation method doesn't depend on empirically-defined unknowns such as Henry's constant, density of solvent-bitumen mixture and etc. Eventually, the effect of neglecting gas-bitumen interface resistance on the predicted values of gas solubility and diffusivity was investigated.
The two key challenges of primary heavy oil production using the process of Cold Heavy Oil Production with Sand (CHOPS) are limited recovery and the environmental footprint. With estimated remaining heavy oil in Western Canada of up to 300 billion barrels there is a significant opportunity for industry. Recovery of this oil using CHOPS is generally limited to 15% maximum brought on by high operating costs due to sand handling and interruption of the reservoir production process due to sand related workovers. The large CHOPS environmental footprint is driven by the significant surface disturbance due to close well spacing, greenhouse gas emissions from the use of heated lease tanks and handling and the long term disposal of produced sand.
Ongoing evaluations show that the SuperSump System has the potential to reduce the environmental footprint and increase recovery of typical CHOPS operations both in new heavy oil fields and in revitalizing existing fields. The technology uses a gravity stable process to drain oil through multiple wells from an upper viscous oil reservoir into a small fit for purpose cavern washed from underlying salt formations. Oil, water, and sand separate in the cavern and clean oil is produced from a single wellbore to surface. The environmental footprint is reduced by eliminating sand handling, reducing lease sizes, and reducing fluid storage and processing on surface. The SuperSump technology also has the potential to reduce operating costs, allowing increased recovery by prolonging the economic well life as production rates decline. In addition, early well failures due to sudden, massive sand influx may be virtually eliminated, encouraging the uninterrupted development of the sand production mechanism in the reservoir. Plugging problems and pump failures may also be eliminated as the wells mature because sand, oil and water are allowed to drain into the cavern below, where sand settles, water separates and sand-free, clean oil is produced to surface.
Simulation work has demonstrated that the SuperSump System could improve CHOPS operations in the following ways: Recovery factors are 50% higher; Operating costs are 30% lower; Energy efficiency is better by 75%; and Greenhouse Gas Emissions are lower by 95%. Estimated costs indicate very favourable economics compared to conventional CHOPS operations.
The analysis of SuperSump System currently focuses on CHOPS operations in the Western Canadian Sedimentary Basin, but could be used anywhere CHOPS is applied. It appears to be especially effective for developing new small fields where the cost of surface facilities constitute a significant portion of the field development cost. SuperSump could also be beneficial in applications where high density drilling is required but there are sensitivities to surface footprint. SuperSump could also be a cost effective precursor to EOR/IOR.
Morvan, Mikel (Rhodia) | Degre, Guillaume (Rhodia) | Beaumont, Julien (Rhodia) | Colin, Annie (LOF (CNRS-Rhodia-Bx1)) | Dupuis, Guillaume (POWELTEC) | Zaitoun, Alain (POWELTEC) | Al-maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman)
Injections of polymer solutions have been used to improve oil recovery in heavy oil reservoirs (Zaitoun et al. 1998). Most of those polymer flood experiences refer to conditions where the polymer solution propagates through the porous media under low shear rate and exhibits mostly a Newtonian behaviour. On the other hand recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically oil recovery of more than 20% OOIP compared to waterflooding has been reported for light oil (Wang et al; 2011). However injectivity issues have to be considered when injecting concentrated polymer solutions. This study examines whether non polymeric elastic fluids derived from surfactant solutions can represent an alternative approach to elastic polymer floods. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity).
Bulk flow properties as well as rheology in a confined geometry have been used to compare flow properties of surfactant and high molecular weight polymer solutions. The elastic properties of both fluids have been characterized in terms of Weissenberg numbers. The data indicate the surfactant solution as opposed to the polymer one is highly elastic at low shear rates even in the presence of brine. Those results are confirmed by comparative experiments made using a Particle Image Velocimetry (PIV) technique. Injectivity of concentrated surfactant solutions has been tested in single-phase conditions and indicated a good in depth propagation of the fluid. A series of core-flood experiments has been performed using heavy oil reservoir cores. The surfactant slug has been combined with a conventional low-concentration polymer flooding to benefit from surfactant elasticity and improve oil recovery.
Steam based thermal processes are major technologies for bitumen and heavy oil recovery. They are energy intensive, high water demand and huge CO2 emission. When such technologies are applied to the reservoir with thief zones, the economics are even worse. In order to increase the efficiency, people are trying to add solvent into steam to reduce the operation pressure and temperature so the economics. The mechanism of adding solvent into is further reducing the viscosity of bitumen or heavy oil an addition to thermal effects. That means the solvent should be dissolved into oil as soon as they meet each other at the interface. The boiling point of the solvent should be near that of steam. When it is to far from steam, it stays either liquid being produced without reacting with oil or gas stopping the heat exchange of steam. In this paper, PVT of some pure and commercial solvents is reviewed and potential operation pressure and temperature are discussed. This can help engineers to select solvent and design the process properly.
It is inescapable that global energy demand is in an increasing trend and will remain so for the coming decades. Heavy-oil and bitumen resources have a significant impact on meeting this demand because of their huge but almost untouched volume, it amounts to it amounts to approximately 70% of world's total oil resources (approximate 6.3-9.1×1012bbl) . With around 7 trillion barrels of heavy oil available globally, the lack of an effcient, feasible, and environmentally friendly heavy-oil production technology is eminent. Steam injection is a proven thermal technique to be used for this purpose and it can be achieved through continuous or cyclic (huff-and-puff) injections. Field experience and simulations studies show that performing these techniques are associated with technical difficulties and usually low recovery factors. Steam Assisted Gravity Drainage (SAGD) is the most used commercial steam-based process being used in bitumen reservoirs, proposed by Butler more than 30 years ago [2,3,4]. The main idea of SAGD was to overcome the problems associated with the highly viscous bitumen by gravity drainages in steam chambers generated by displacement of heavy oil .
SAGD is not economic in cases where reservoirs are thin, because heat losses to confining strata become excessive compared to the resource. Another problem in SAGD is the cost involved for treating effluent water and the high energy requirements in order to have a continuous production of steam. On the other hand, huge quantities of heavy oil are trapped in tight but fractured carbonate reservoirs. Until recently, except for limited efforts in the applicability of steam injection at a field pilot scale, there was no method introduced to produce heavy oil from fractured carbonate reservoirs .
Considering the drawbacks of the conventional SAGD process, some modifications and even alternative recovery processes were proposed to enhance the overall performance of the SAGD process such as the use of solvent (noncondensable gas) along with the injected steam phase to reduce the amount of heat loss to the overburden and also low-pressure SAGD. Those techniques include miscible flooding (VAPEX) or modified versions of SAGD (ES-SAGD) through different configurations of wells or using additives to steam [7,8]. Although steam solvent process(SSP)is a highly promising technique, many uncertainties and unanswered questions still exist and they should be clarified for SSP to world wide applications. The boiling point of the solvent should be near that of steam. When it is to far from steam, it stays either liquid being produced without reacting with oil or gas stopping the heat exchange of steam. In this paper, PVT of some pure and commercial solvents is reviewed and potential operation pressure and temperature are discussed. This can help engineers to select solvent and design the process properly.
Zolotukhin, Anatoly Boris (Gubkin Russian State University of Oil & Gas) | Bokserman, Arkady (Zarubezhneft Joint Stock Company) | Kokorev, Valery (RITEK ltd.) | Nevedeev, Andrey (D-Sintez) | Ushakova, Alexandra (Zarubezhneft Joint Stock Company) | Shchekoldin, Konstantin (RITEK ltd)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Heavy Oil Conference Canada held in Calgary, Alberta, Canada, 12-14 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Heavy oil and bitumen are found in many places worldwide, with the largest deposits in the world being in Canada (Alberta), Venezuela and the former Soviet Union.