Horizontal Producer Research Articles

エマルション生成, CO<sub>2</sub>フォーミィオイル生成および原位置燃焼による重質油の生産挙動について

Enhanced oil recovery (EOR) processes have been applied to improve mobility of heavy oil and bitumen. This article has introduced three topics on numerical models for heavy oil and bitumen productions based on laboratory measurements and their scaling up to field reservoir simulations using CMG STARS™.First one is CO2 gas foaming by depressurizing after immiscible CO2 dissolution in heavy oil. Saturated CO2 solubility and apparent swelling after foaming were measured on decreasing pressure processes using PVT apparatus and a high pressure cell. The numerical models of apparent viscosity and swelling ratio for foamy heavy oil have been proposed based on the measurement data and applied to a field scale oil-reservoir by Huff-n-Puff production methodThe second one is bitumen emulsion (water in oil) formed by the Steam Assisted Gravity Drainage (SAGD) method for oil-sands layers, because condensed fine water-droplets diffuse into bitumen at the steam-chamber boundary. The characteristic of heavy-oil viscosity was measured against water/oil ratio (W/O) and temperature. The model of viscosity ratio (emulsion/original) vs. W/O has been presented and investigated its effect on bitumen-production from a typical oilsands reservoir by SAGD method. Finally, it has been shown that cumulative bitumen-production increases with bitumen swelling function of W/O.The third one is heavy oil recovery by in-situ combustion with injecting air or O2 gas. Recently, the Toe-to-Heal Air Injection (THAI) method using a vertical injector and a horizontal producer is expected to be able to keep stable combustion front and oil drainage flow into the producer. Based on our numerical history-matching study on the tube combustion test for bitumen sands-pack, the reaction model consists from 3 major reactions were screened from 8 chemical reactions on Maltenes, Asphaltenes and Coke. Finally, the model was successfully applied to a heavy-oil in-situ production from a typical field oil reservoir.

A Geosteering Success Story From the North Sea

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159132, ’Geosteering the Impossible Well: A Success Story From the North Sea,’ by Soazig Leveque and Christophe Dupuis, Schlumberger; Thomas Stærmose, Estela Vazquez Esmerode, and Peter Sommer Linnet, DONG E&P; and Graham Raeper, Schlumberger, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed. The Nini East field represent a significant drilling challenge. The target is a post-depositionally remobilized sand reservoir with a thickness of 2‒15 m. None of the standard well-placement methods or current mapping tools was a suitable solution for the well objectives. A field test of the next-generation bed-boundary mapping tool was launched to geosteer two upcoming production wells. The two producers achieved an outstanding 0.99 and 0.96 net pay ratio with no sidetracks or delays and were completed within budget. Introduction The Nini East field is located 3 km south of the border between the Danish and Norwegian sectors of the North Sea (Fig. 1) and was discovered in 2001, when oil was found in the Kolga-member sandstones of the Upper Paleocene/Lower Eocene Sele formation. The challenges in drilling horizontal wells in this type of reservoir include a complex geological setting—leading, in some wells, to a low net-pay ratio—combined with the unstable reservoir- capping Sele shale, which increases the risk of having to drill sidetracks. The Kolga-member reservoir of the Nini East field consists of a glauconite-rich sandstone with unique characteristics. Although initially deposited as traditional gravity-flow sands, the Kolga sands have been remobilized under burial, leading to sand fluidization and injection along weakness zones. These traits create difficulty in defining the exact stratigraphic location of the sand. With these challenges in mind, the Dansk Olie og Naturgas company (DONG E&P) launched the development of the Nini East field in 2009 with a drilling campaign including two horizontal producers and one injector in the Kolga sand. The two main goals were to increase the percentage of horizontal section in pay while avoiding the Sele shale and maintaining the oil/water-contact (OWC) standoff. Methodology The operator decided that much-needed uncertainty reduction could only come from significant investment in seismic-data processing and inversion, combined with the new- generation deep-directional-electromagnetic (DDE) service-placement workflow. The seismic data were reprocessed and inverted to improve the imaging of the injectite sands. The seismic resolution was improved from approximately 10 m on the conventional seismic data to approximately 5 m on the inverted cube (Fig. 2). The primary method of trajectory adjustment involves correlating the logging-while-drilling (LWD) log response acquired on a drilling well with offset data acquired along previously drilled wells in the area. This implicitly relies on the assumption that the formation is continuous between the offset wells and the current drilling location—an assumption that may not hold in faulted reservoirs, pinchouts, unconformities, or highly remobilized reservoirs such as those found in the Nini East field.

SAGD-Pair Performance Optimization: A Field Case Study of Recovery Enhancement

Summary Performance of fields under thermal recovery processes has been improved considerably by experimenting with new techniques and innovative operational solutions in heavy-oil and extra heavy oil fields (Butler 1994; Singhal et al. 1998). By far, steam-assisted-gravity-drainage (SAGD) and cyclic-steam-stimulation (CSS) methods have been the most compelling and have shown a successful history in these oil fields (Butler et al. 2000; Butler 2001). At the Celtic heavy-oil field, Husky Energy experienced three phases of optimization over the course of 10 years of recovery. The Celtic field consists of 28 SAGD pairs located in the Lloydminster heavy-oil region that have been in service since 2001. Among these pairs, there are three SAGD pairs (F Pad East) with early productivity challenges in addition to downtime caused by sand production. Following new geological realization and reservoir studies, the injector wells were converted to production wells performing a horizontal CSS process. In 2008, and in an effort to maintain production, a detailed numerical-simulation study was conducted to compare different steam support configurations and the result was justified for field execution. The outcome resulted in four directional steam-injection wells (G Pad) permanently started to support the current horizontal producers. In 2009, the new configuration commenced and is still in operation today. Communication with horizontal wells has been confirmed on one side of the pattern, and it has been extending gradually to the other side as it was investigated in other work (Edmunds 1991; Al-Salhi et al. 1997). Recently, acquired field data suggest that the process is exceeding the expected oil profile and its steam consumption is less than anticipated. The geological review, history of the F Pad East pairs, results of numerical-simulation study, and recommendations are presented in this paper.

Reservoir Management for World's First Thermal Gas/Oil Gravity-Drainage Project

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 153967, ’A Reservoir Management System for the World's First Thermal Gas/ Oil Gravity-Drainage Project,’ by Keith Rawnsley, SPE, Augustine Ikwumonu, SPE, Solenn Bettembourg, Pristwanto Putra, SPE, and Ibrahim Al-Ismaili, SPE, Petroleum Development Oman, prepared for the 2012 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 16-18 April. The paper has not been peer reviewed. The world’s first full-field thermally assisted gas/oil gravity-drainage (TAGOGD) project has begun in Oman (Fig. 1). Historically, the field was operated at very high water cut because of aquifer influx through the fractures to the producers. The recovery process was a mixture of gas/oil gravity drainage and water/oil gravity drainage, but the high oil viscosity and low matrix permeability prevented recoveries from reaching more than a few percent. To attempt to unlock the oil in place, a TAGOGD development concept has been piloted in the field over approximately 10 years. This led the way to the full-field project that has now begun. Introduction Steam, mainly generated by heat-recovery steam generators, is injected into the natural fractures at the crest of the reservoir, and the fractures distribute the steam in the reservoir. As the oil in the matrix is heated, its viscosity decreases by a factor of 100 and it drains down by gravity through the matrix into the fracture oil rim. From there, it is sent to the production facility (Fig. 2). The field’s life can be divided into two phases. The first phase, now under way, is the transition period during which the oil rim in the fractures is lowered from its position near the top of the reservoir to a position close to the matrix oil/water contact. This increases the oil column height exposed to TAGOGD to more than 100 m. This period is expected to last approximately 2 years, and production is through gas lifted producers, which are wells inclined 45° to intersect fractures. The second phase is the plateau/tail period, when the oil rim will be maintained at its deep position. Production in the second phase will be through horizontal producers drilled close to the oil/water contact. Modeling The thermal gas/oil gravity process will be the first application of the technique at field scale in the world. Modeling, therefore, has taken and will continue to take a more substantial role than it has in more conventional fields, both to build confidence and to act as an interface between the reservoir surveillance data and opportunity generation. The modeling strategy is designed to ensure that predictions are accurate, to capture ongoing uncertainties, and to improve with experience. As more data become available, the understanding will improve, which will be reflected in changes in the modeling strategy.

Experimental analysis of Combustion Assisted Gravity Drainage

Abstract Combustion Assisted Gravity Drainage (CAGD) is a new EOR process that uses dual horizontal wells for the injection of air and the production of heavy oil. One of the important features of CAGD is the properly oriented dual horizontal wells, similar to SAGD, which assists in the development of combustion chamber and stable growth of the combustion front in the reservoir. This research evaluates the potential of CAGD as an attractive alternative to conventional in-situ combustion (ISC). A 3D laboratory model was designed and constructed to study the CAGD process. The combustion cell was fitted with 48 thermocouples. A horizontal producer was placed near the base of the model with a horizontal injector in the upper part. The CAGD process combines the advantages of both gravity drainage and the conventional ISC. Experimental results showed the combustion chamber developed in the wide area of the porous media around the horizontal injector. This combustion chamber consisted of flue gases, injected air and hot oil. The gravity drainage is the main mechanism for oil production and extracting the flue gases from reservoir. Recorded temperatures reached up to 650 °C at the combustion front, with oil recovery more than 82% OOIP. Experimental data showed that improper well distance could cause severe plugging in production well perforations and terminate the process prematurely.

A New SAGD-Well-Pair Placement: A Field Case Review

Summary Steam-assisted gravity drainage (SAGD) has been improved consistently by experimenting with various solutions in both oil sands and heavy-oil fields in Canada (Butler 1994; Singhal et al. 1998). The SAGD process consists of two stacked horizontal wells and is proven technology in heavy-oil fields (Butler and Yee 2000). Employing the same concept of gravity drainage, SAGD-well placement convention has been revisited and challenged many times (Birrell and Putnam 2000; Edmunds 1991; Parappilly and Zhao 2009). Known to the industry, the cross-SAGD (also called XSAGD) (Stalder 2007) and J-shaped well steam-assisted gravity drainage (JAGD) (Larter et al. 2008) processes are two examples of fit-for-purpose well design and recovery schemes that require unique drilling practices. The Celtic pool, located in Lloydminster, Saskatchewan, is an active Husky Energy Incorporated (Husky) thermal field that includes 31 SAGD well pairs. In this heavy-oil pool, one of the SAGD well pairs (I3/I4; Well I3 as producer and Well I4 as the injector) experienced production downtime soon after coming into service. Following numerous unsuccessful service jobs, several re-entry options were suggested in order to recover remaining reserves. These included sidetracking Well I3, redrilling a new well from the same pad location, or commencing a new well from a different surface location. These cases were ranked, and in 2010, on the basis of a drilling-risk assessment, the new horizontal producer well (I3A) was drilled close to the existing well pair. Well I3A was placed counter currently below the existing injector well (I4) and set successfully parallel to the abandoned Well I3. Steam conditioning was completed in the first quarter (Q) of 2011, and the new SAGD well pair (I3A/I4) has been put on production successfully. The new well pair was positioned in the opposite direction of a conventional SAGD-well-pair placement. This paper presents the original I3/I4 pair performance, the challenges, results of redrilling Well I3A, reservoir-simulation study, and recent field production of the I3A/I4 SAGD well pair.

Real-Time Distributed-Temperature and Downhole-Pressure Surveying To Quantify Skin

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 155723, ’The Use of Real-Time Downhole Pressure and Distributed- Temperature Surveying in Quantifying the Skin Evolution and Zone Coverage in Horizontal-Well Stimulation,’ by Abdulelah A. Balto, SPE, Hassan B. Qahtani, and Khaled A. Kilany, Saudi Aramco, and Fernando Baez, SPE, and Tamer Elsherif, SPE, Schlumberger, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed. Fiber-optic-enabled coiled tubing (FOECT) has been used recently to evaluate reservoir-matrix chemical treatments qualitatively in real time. Attempts have been made to transform qualitative evaluations into quantitative ones. Pressure-transient analysis yields the skin value as a direct output, while the cooling-down/warming-up distributed-temperature-survey (DTS) profile identifies where treatment fluids went into the formation, hence identifying damaged zones. Combining well-test-analysis techniques with zonal-coverage evaluation is recommended strongly in highly deviated and horizontal wells in both clastic and nonclastic rocks. Introduction The near-wellbore rock matrix is where most of the permeability damage occurs from mud filtrate, adverse oil or water saturations, and clay migration. A sandstone-matrix treatment has multiple challenges including uncertainty in the lithology of the rock, uncertainty in damage identification, and secondary reactions that may cause blocking rather than stimulation. A main challenge is obtaining uniform coverage of the treatment across the zone of interest. Therefore, the need for proper placement technique arises. Even though many diverting techniques have been developed in the past years, the challenge still exists in horizontal wells, especially with long sections that require optimizing placement of the treatment fluids, diverters, or reactive fluids. The complete paper details two challenges related directly to the operational side of stimulation: real-time, simultaneous fluid-placement optimization and treatment-effectiveness evaluation. Case Overview Well-A is a horizontal oil producer off-shore Saudi Arabia. The horizontal section extends approximately 3,400 ft in a clastic formation. The well was completed with inflow-control devices wrapped with a premium screen. It is believed that, since the beginning of production, the well has been underperforming and significant unwanted water is produced. Challenges. As with most underperforming wells, several challenges are encountered in optimizing hydrocarbon production. Proper damage identification and appropriate treatment-fluid selection are critical enablers for success. The job design includes the placement technique, completion limitations, and any other factor affecting the success of the chemical treatment. The evaluation process in long horizontal wells is slightly more complex than in vertical and deviated wells. The two main factors in such an evaluation are zonal coverage and skin reduction (i.e., gained pressure and, hence, a gain in production at the same outflow conditions).

Effect of well pattern and injection well type on the CO2-assisted gravity drainage enhanced oil recovery

Fundamental understanding and application of process parameters in numerical simulation that leads to optimized gravity drainage oil recovery at field scale is still a major challenge. Reservoir simulations studying the effects of well patterns and type of gas injection wells have not been reported so far. In first ever attempt, the mechanistic benefits of production strategy on gravity drainage oil recovery are identified in this paper. Effects of irregular and regular well patterns and vertical and horizontal gas injection wells are investigated using a fully compositional 3D reservoir model in secondary immiscible and miscible modes under the conditions of voidage balance, constant pressure of injection and production wells and injection rates below the critical rate. Regular well pattern provided longer oil production time at a constant rate until CO2 breakthrough compared to irregular well pattern. It then dropped almost vertically at the same cumulative oil recovery even at higher production rates. However, gravity drainage oil recovery was higher at higher rate combination after CO2 breakthrough. Results also suggested that the regular pattern could result in horizontal CO2 floodfront parallel to the horizontal producers, maintaining reservoir pressure, thus optimizing the oil recovery by additional 2.5% OOIP. Vertical injection and horizontal production wells in both the immiscible and miscible modes provided nearly identical cumulative gravity drainage oil recovery compared to the combination of horizontal injection and production wells in the regular well pattern. This suggests that the type of injection wells may not be a significant factor to impact the CO2-assisted gravity drainage mechanism. Results obtained herein would help in the optimization of CO2-assisted gravity drainage EOR process.

Meeting the Challenges in Downhole Scale Control for High-Water-Production Horizontal Wells in an Environmentally Sensitive Part of the Norwegian North Sea

Summary As a result of the seawater injections in one of the Norwegian North Sea oil fields, sulfate-scale depositions have been identified in the near-wellbore region and inside the production well. Scale-inhibitor squeeze treatments are carried out regularly. Most of the production wells are horizontal producing, with a fairly high water cut, and increasing the squeeze treatment life is one of the major issues for the selection of scale inhibitors and placement technologies. In addition, the inhibitor selected has to be environmentally acceptable and meet regulations from environmental authorities. Both challenges from the high-water-production wells and environmental requirements limited the choice of the inhibitor candidate selections. Through extensive laboratory qualification testing, a newly developed polymer inhibitor was qualified for the field and satisfactory results were achieved from several field trials. This paper presents the inhibitor chemistry, as well as laboratory tests such as inhibitor efficiency and compatibility and inhibitor coreflood. The environmental properties of the chemistry will be outlined. A comparison was made between the field treatments using this polymer inhibitor and widely applied polymer chemistries. The treatment optimization using a software package will also be highlighted. The field used a gelled scale-inhibitor package, and the technology improved the inhibitor placement in the horizontal well. The updated treatment data will be reviewed in this paper.

Next-Generation Production Control Aids Multiple Dipping Sandstone Reservoirs

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 145854, ’Implementation of Next-Generation Intelligent Downhole Production Control in Multiple Dipping Sandstone Reservoirs, Offshore East Malaysia,’ by J.H. Chris Chen, SPE, N.M. Azrul, B.M. Farris, K.Z. NurHazrina, M.K.M. Aminuddin, and M.Y. Saiful Anuar, Petronas Carigali, and K.F. Gordon Goh, SPE, K.S. Premjit Kaur, T.K. Darren Luke, and A. Eddep, Schlumberger, prepared for the 2011 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 20-23 September. The paper has not been peer reviewed. A next-generation intelligent-completions system was implemented successfully in a complicated, highly dipping, multilayered sandstone reservoir with commingled production. In this multizonal production solution, the conventional surface-controllable downhole zonal flow-control valves are now integrated with data-surveillance gauges, intelligent sensors, and isolation packers into one completion joint, compared with the previous multijoints system (i.e., splicing of up to three joints per zone required conventionally). This single modulated joint system has reduced installation time substantially compared with conventional intelligent-completions installations. The risk of surface completions makeup damage before running in hole is also greatly reduced with fewer connecting components. Introduction The S field offshore East Malaysia consists of multiple dipping heterogeneous sandstone reservoirs with unconsolidated formation (Fig. 1). These multi-stacked reservoirs have an overall 40-m-thick oil column with margin-al oil initially in place (OIIP). A large gas cap (i.e., twice the OIIP equivalent) also exists. Because horizontal wells are recognized as one of the more productive development options in exposing wellbore to maximum reservoir con-tact and drainage area for recovery economics, the decision was made to drill 14 horizontal wells for the first batch of field development. This development option has reduced the number of well counts significantly while maximizing reservoir-drainage points, thus making the project economics for developing this marginal field greatly improved. Two of the 14 horizontal producer wells in this marginal field have been screened to apply the modular integrated-intelligent-completions system (IICS) to actively control and permanently monitor zonal inflow for optimal production. Developing a Thin-Oil-Rim Field Intelligently The downhole active-flow-control-solution application in the horizontal well was one of the selected strategies to complete wells in these complicated geology structures while enabling zonal-contribution adjustment and future zonal selectivity. This is an intelligent alternative zonal management option compared with the other passive version of the inflow-control-device applications in the same field. Out of the eight commingling producers analyzed, two oil producers (i.e., Well-A1 and Well-A2) were selected as potential candidates for the intelligent-completions design. The significant zonal-reservoir-deliverability contrasts for Well-A1 and Well-A2 proved suitable for an initial zonal-influx balancing and later reactive inflow solution.

The Application of Horizontal and Vertical Well Patterns During Polymer Flood Processes in Anisotropic Reservoirs

Using horizontal wells in a polymer flood process, higher sweep efficiency is expected compared with the use of conventional patterns by vertical wells. However, the use of horizontal wells is very sensitive to the well pattern designed to operate the process. This article presents an analysis of how the overall performance of a polymer flood process is influenced by the well pattern using a horizontal injector and producer in different configurations. A three-dimensional numerical model for fluid flow and mass transport is used to analyze the performance of the reservoir. The potential for a horizontal well application was assessed through different scenarios in combinations of injection and production wells and reservoir anisotropy. Results from the study have demonstrated that a significant amount of additional oil can be recovered and injectivity was remarkably improved by utilizing a combination of horizontal wells. The improvement of injectivity through a horizontal injection well was higher when it was combined with a horizontal producer parallel to the injector. The overall performances in anisotropic reservoirs strongly depend on the type of wells considered and the orientation of the horizontal wells with respect to the permeability directions. A combination of horizontal wells placed parallel to the low permeability direction yields the best performance.

Effect of Oil-Viscosity-Gradient Presence on SAGD

Summary The presence of an oil-viscosity gradient appears to be a real phenomenon in the field, and its influence on the steam-assisted-gravity-drainage (SAGD) process has been studied by various researchers. However, there is potential to refine previous results to exploit the impact of viscosity gradients on SAGD-oil-recovery-process performance. This paper covers our simulation study of the impact of an oil-viscosity-gradient presence on SAGD operation. Various SAGD operating scenarios in the reservoir with the presence of a vertical oil-viscosity gradient were investigated and simulated. The conclusions are summarized as follows: The presence of a vertical oil-viscosity gradient in the reservoir had a mild effect on the SAGD-oil-recovery rate, while the effect on the oil-recovery factor was insignificant. J-Well SAGD, in which a J-well replaces the horizontal producer in a standard SAGD-well configuration, did not perform as well as SAGD with a standard well configuration (two parallel horizontal wells). These two conclusions are not in agreement with previous findings by other research groups. Observations from some SAGD field tests indicate that the steam chamber could fail to reach the top of reservoirs. For those cases, gas injection could potentially help to recover the oil from the layer above the steam chamber. If that is true, the presence of an oil-viscosity gradient might have some impact on SAGD performance with gas injection. Because local steam-trap control is required for J-Well SAGD (JAGASS) operation to optimize performance, the challenge and feasibility of local steam-trap control are also discussed in this paper. Some of the SAGD field evidence will be provided to support our simulation results.

Efficiency of Horizontal and Vertical Well Patterns on the Performance of Micellar-Polymer Flooding in Anisotropic Reservoirs

There is increasing interest in micellar-polymer flooding because of the need to increase oil production from depleted and waterflooded reservoirs. Using horizontal wells for injection and production in a micellar-polymer flood process, higher sweep efficiency is expected compared with the use of conventional patterns by vertical wells. However, the use of horizontal wells is very sensitive to the well pattern designed to operate the process. This paper presents an analysis of how the overall performance of a micellar-polymer flood process in anisotropic reservoirs is influenced by the well pattern using horizontal injector and producer in different configurations. A three-dimensional numerical simulator for fluid flow and mass transport is used to analyze the effectiveness of well combinations in micellar-polymer applications. The potential for a horizontal well application was assessed through different situations in combinations of injection and production wells and degree of reservoir anisotropy. Results from the study have demonstrated that significant amount of oil can be recovered additionally and injectivity was remarkably improved by utilizing a combination of horizontal wells. The improvement of injectivity through a horizontal injection well was higher when it was combined with horizontal producer parallel to the injector. The overall performances in anisotropic reservoirs strongly depend on the type of wells considered and the orientation of the horizontal wells with respect to the permeability directions. Combination of horizontal wells placed parallel to the low permeability direction yields the best performance. In high permeability ratio reservoirs, the presence of horizontal injectors is more significant in defining the efficiency of the micellar-polymer flood than the horizontal producers. Key words: Micellar-polymer flood; Horizontal well; Anisotropy; Injectivity

Validation of Toe-to-Heel Air-Injection Bitumen Recovery Using 3D Combustion-Cell Results

Summary Rigorous validation of a simulation model of the toe-to-heel air-injection (THAI) process has been performed using results obtained from a 3D combustion-cell experiment on Athabasca oil sands. The numerical model includes a new kinetics formulation, based on the Athabasca thermal-cracking kinetics scheme proposed by Phillips et al. (1985). The kinetics model excludes low-temperature oxidation because THAI operates in a high-temperature oxidation mode. Excellent agreement was obtained between the predicted and experimental oil-production rate, and there was generally a good match obtained for other dynamic variables, including the residual coke profile, produced oxygen, and peak combustion temperature. The numerical model provides a fundamental platform for upscaling to field scale that will enable fine-scale details of the process to be captured. Simulations were performed under dry in-situ combustion (ISC) conditions at the high air-injection fluxes used in the experiment. Under these conditions, vertical-plane temperature profiles in the sandpack confirm that the combustion front is quasivertical and forward leaning in the direction of the heel of the horizontal producer well. The shape of the combustion front was predicted more accurately from horizontal-plane profiles, showing that there was no oxygen in regions ahead of the combustion front. Oil displacement occurs mainly by gravity drainage, but pressure drawdown into the horizontal producer well below the mobile-oil zone (MOZ) is also significant. Various zones that develop during the ISC process include a steam zone located in the upstream part of the MOZ. All of the mobilized oil is produced from the MOZ, which is composed of two distinct oil regions. The first part contains oil produced by thermal cracking of the heavy residue and vaporized lighter oil. The main bulk of the oil produced in THAI comes from the second region of the MOZ, containing banked original oil. The oil that is eventually produced is partially upgraded oil because of the thermally upgraded and lighter oil fractions mixing with the original oil when they enter the horizontal producer well.

The Operational and Reservoir Parameters Influencing the Performance of Top-Down In Situ Combustion in Fractured Reservoirs: 2D Block-Scale Simulation of Networked Fractures

Top-down in situ combustion (ISC) involves the stable propagation of a combustion front from the top vertical injector to the bottom horizontal producer. With the exception of laboratory studies of conventional sandstones, no application of the process in fractured carbonates has been addressed. The aim of the present work is to study ISC in the presence of a system of networked fractures using a thermal reservoir simulator from the Computer Modeling Group (CMG; Calgary, AB, Canada). The performance of ISC is compared with nonfractured system under similar conditions. To obtain more realistic results, a history-matched and validated combustion model of an Iranian naturally fractured low-permeability carbonate heavy oil reservoir, Kuh-E Mond, was used, and the performance of ISC in a fractured porous medium model was compared with a conventional (nonfractured) reservoir. Operational and reservoir parameters that may influence the performance of the process in the case of a fractured reservoir, such as air injection rate, initial oil saturation, initial water saturation, reservoir pressure, matrix permeability, vertical and horizontal fracture density, and the effect of water–oil capillary forces on the recovery of the process have been investigated. Simulation results showed that in the presence of fractures the recovery rate was slower compared to conventional model. Air breakthrough occurred at almost the same time in both models but the amount of oxygen in the exhaust gas for the fractured model was quite high compared to the conventional model, which was near zero. The presence of fractures resulted in lower API gravity of the recovered oil; that is, upgrading of crude oil during the ISC process was lower for the fractured system.

The Effect of Fractures' Geometrical Properties on the Recovery Mechanism of the Top-down In Situ Combustion Process

The top-down in situ combustion (ISC) involves the stable propagation of the combustion front from the top vertical injector to the bottom horizontal producer. Apart from laboratory studies in conventional sandstones, no application of the process in fractured carbonates has been addressed yet. The authors modified a successful combustion tube history matched model of an Iranian low-permeable heavy oil reservoir called Kuh-E-Mond to investigate the feasibility of ISC in fractured carbonate reservoirs mimicking block-scale combustion cells. Effects of fractured geometrical properties such as orientation, location, extension, density, spacing, and dispersion were considered. Results confirmed a higher outcome in the case of optimum vertical or horizontal fracture density and spacing. Vertical fractures located at the lateral sides of the cell enhanced the process in terms of ultimate oil recovery and oxygen sweep efficiency. The longer vertical fractures and higher dispersion through the reservoir improved the recoveries compared with the lower efficiency in the case of extended horizontal fractures and raised their dispersion through the reservoir. Simulation analysis confirmed that top-down ISC has higher feasibility in the case of highly networked fractures through reservoirs such as those in the Persian Gulf coast.

Efficiency of Horizontal and Vertical Well Patterns on the Performance of Micellar-polymer Flooding

There is increasing interest in micellar-polymer flooding because of the need to increase oil production from depleted and waterflooded reservoirs. Using horizontal wells for injection and production in a micellar-polymer flood process, higher sweep efficiency is expected compared with the use of conventional patterns by vertical wells. This paper presents an analysis of how the overall performance of a micellar-polymer flood process is influenced by the well pattern using horizontal injector and producer in different configurations. Results from the study have demonstrated that significant amount of oil can be recovered additionally and injectivity was remarkably improved by utilizing a combination of horizontal wells. The improvement of injectivity through a horizontal injection well was higher when it was combined with horizontal producer parallel to the injector.

Tee-SVX: Enhanced Oil Flow Rate in Solvent Vapor Extraction Process

The production rate in classical vapor extraction (VAPEX) is far too low for the process to be considered commercially viable. This is largely because the classical process utilizes forces of buoyancy and mass transfer by diffusion and dispersion to distribute the solvent and gravity to drain the diluted oil to the producer. This article presents a new well pattern Tee-SVX which may enhance the oil-flow rate by two to ten times over that of the classical approach. In the new well pattern, additional horizontal injectors, perpendicular to the injector and the producer in Classical VAPEX, are placed in the topmost region of a reservoir. The oil-rate-enhancement mechanism for this new well pattern involves two features. First, the operation pressure of the top injectors is set slightly higher than the bottom injector pressure. This facilitates a downward driving force to assist gravity drainage of diluted oil to the producer. Second, the supplementary injectors generate an additional diluted oil profile perpendicular to the diluted oil profile of the Classical VAPEX process. Therefore, in the new well pattern, the heavy oil is solvent contacted and diluted in both vertical planes (one plane perpendicular to and the other parallel to the horizontal producer), whereas in Classical VAPEX, the heavy oil is diluted in only one. A series of numerical simulations were conducted to evaluate this process. In order to obtain reliable evaluation results, the numerical dispersion was eliminated through extrapolating the simulation results at different grid sizes to an infinitesimal grid size (Δy → 0). The simulation results suggest that the oil-flow rate can be enhanced two to ten times greater than that with Classical VAPEX, depending on the well spacing of the top injectors. For example, for a well spacing of the top horizontal injectors of 120 m, the oil-flow rate from the original producers will be 5.5 times higher than that of Classical VAPEX. For thinner reservoirs, the Tee-SVX can enhance the oil-production rate higher compared with Classical VAPEX. For reservoirs with a small gas cap, Lateral-SVX with vertical injector is quite effective.

Experimental Optimization of Catalytic Process In Situ for Heavy-Oil and Bitumen Upgrading

Summary The worldwide conventional crude-oil demand is on the rise, and because of the rising prices, unconventional oils are becoming more economically attractive to extract and refine. However, technological innovation is needed if heavier oil supplies are to be exploited further. Toe-to-heel air injection (THAI) and its catalytic add-on processes (CAPRI) combine in-situ combustion with catalytic upgrading using an annular catalyst packed around the horizontal producer well. These techniques offer potentially higher recovery levels and lower environmental impact than alternative technologies (e.g., steam-based techniques). An experimental study is reported concerning the optimization of catalyst type and operating conditions for use in the THAI-CAPRI process. The feed oil was supplied from the Whitesands THAI-pilot trial. Experiments were carried out using microreactors containing 10 g of catalyst, with oil flow of 1 mL/min and gas flow of 0.5 L/min, under different temperatures, pressures, and gas environments. Catalysts tested included alumina-supported CoMo, NiMo, and ZnO/CuO. It was found that there was a trade-off in operation temperature between upgrading performance and catalyst lifetime. At a pressure of 20 bar, operation at 500°C led to an average of 6.1°API upgrading of THAI oil to 18.9°API, but catalyst lifetime was limited to 1.5 hours. Operation at 420°C was found to be a suitable compromise, with upgrading by an average of 1.6°API, and sometimes up to 3°API, with catalyst lifetime extended to 77.5 hours. Coke deposition occurred within the first few hours of the reaction, such that the catalyst pore space became blocked. However, upgrading continued, suggesting that thermal reactions or reactions catalysed by hydrogen transfer from the coke itself play a part in the upgrading reaction mechanism. The CAPRI process was relatively insensitive to changes in reaction-gas medium, gas-flow rate, and pressure, suggesting that the dissolution of hydrogen or methane from the gas phase does not play a key role in the upgrading reactions. By careful control of the temperature and oil-flow rate in the in-situ CAPRI process, additional upgrading compared with the THAI process alone may be effected, resulting in a more-valuable produced oil, which is easier to transport.

Physical Simulation on Temperature and Pressure Fields during Steamflooding through Horizontal Wells in Heterogeneous Reservoir

—Temperature and pressure fields distribution during steam flooding through horizontal wells is very important to researches. The present experimental study is conducted to investigate the effect of steam flooding through horizontal injector-horizontal producer when high permeability section exists in the horizontal section and the ratio of permeability is 1:8. And 13 differential pressure transducers with high accuracy are installed in the model to measure the pressure field variation in reservoir during the experiments. And 13 differential temperature thermocouples are put on the model to measure the temperature field variation. Water cut and cumulative oil recovery are obtained. And effects of heterogeneity on temperature and pressure fields are obtained from experiment.