The four papers in this month’s issue offer useful and timely contributions in the areas of heavy-oil/bitumen recovery by solvent injection, estimating fracture volume in shale-gas wells, and gas-lifting of waxy-crude oils.
Solvent plus steam-injection processes offer the potential for reducing the environmental impact and costs associated with the production of heavy oils over traditional steam-injection methods. For example, the additional of small amounts of solvents to steam is proven to improve oil recovery over steam injection alone. This effectively translates into a reduction in steam requirement, which directly impacts water usage and atmospheric emissions. The first two papers deal with the performance of sequential steam/solvent injection in fractured and wormholed-type reservoirs, and a means of upscaling solvent dispersion in heterogeneous reservoirs to the reservoir scale.
Experimental Analysis of Heavy-Oil Recovery by Alternate Injection of Steam and Solvent (Hydrocarbon/CO2) in Unconsolidated Sand Reservoirs examines the performance of steam-over-solvent injection in water-wet and oil-wet systems having hydraulic features similar to matrix/fracture media. The solvents considered have different vapour pressure behaviours (CO2, propane, and butane), and the use of varying operating pressures as well as hot water vs. steam for hydrocarbon solvent recovery is evaluated. A substantial amount of experimental data are presented that provide useful insights into oil-recovery mechanisms and the potential for optimizing the process. This paper also notes that the oil-recovery efficiency of these solvents must be considered in conjunction with life cycle objectives of being able to ultimately sequester CO2 vs. the economic necessity of having to recover hydrocarbon solvents.
Scaleup of Effective Mass Transfer in Vapour-Extraction Process Accounting for Field-Scale Reservoir Heterogeneities systematically investigates the relationship between effective solvent/oil mass-transfer coefficients and reservoir-scale heterogeneities. The approach uses volume-averaging of fine-scale numerical flow simulation of the vapour extraction (VAPEX) process to provide a description of mass transfer at coarser scales. Heterogeneities are shown to improve mass transfer caused by dispersion by creating a larger interfacial contact area. The procedure for quantifying the mass-transfer scaling characteristics is well documented and a good introduction to the subject is provided. There is little doubt that contributions of this kind are a welcome addition to the technical literature.
One of the challenges associated with shale-gas operations is the substantial volume of fracture fluid that must be injected and subsequently disposed of in order to create the required well productivities in horizontal wells. Given the complexity and cost of these shale-gas well completions, there is a real opportunity to improve both their cost and performance metrics. Improved production data interpretation procedures will be beneficial in this regard. Using a comprehensive treatment that combines flowback and production data, the next paper offers a means of estimating the post-treatment fracture volume. Estimation of Effective-Fracture Volume Using Water-Flowback and Production Data for Shale-Gas Wells demonstrates the proposed methodology with field data from the Fayetteville and Barnett formations. This paper is clearly written and informative.
The last paper addresses the pervasive problem of sustaining oil production from waxy-crude wells. This particular flow assurance issue is compounded if gas lift is employed for artificial lift because the cooling effect of the injected gas increases the potential for wax deposition within the wellbore. A Transient Two-Phase Fluid- and Heat-Flow Model for Gas-Lift-Assisted Waxy-Crude Wells With Periodical Electric Heating describes a new algorithm developed from drift-flux theory for computing temperature distributions in concentric pipes with two-phase flow. The authors apply the model to optimize production operations in a mature waxy-crude field in China. The algorithm is able to provide the appropriate heating schedule and landing depth for an electrical cable situated within the tubing. This avoids wax precipitation within the well, while minimizing electrical costs. A useful contribution, indeed.
The papers in this issue all narrow important technological gaps in oil and gas production. I hope you benefit from them as much as I did.
John D.M. Belgrave, PhD, MBA, P.Eng
John D.M. Belgrave is a petroleum/reservoir engineer with more than 30 years of diversified oil and gas experience. He is president and CEO of Belgrave Oil and Gas Corporation, a private petroleum-development company focused on the development and application of high-impact improved/enhanced oil-recovery (IOR/EOR) technology. Belgrave has been involved with the design and implementation of several oil and gas exploitation and EOR projects in Trinidad, Canada, Colombia, Brazil, the United States, Kazakhstan, and Libya. He has extensive petroleum-engineering experience, but his focus has been reservoir characterization, simulation and EOR, particularly air and steam injection. Belgrave’s project management experience includes building, mentoring, and supervising multidisciplinary teams, capital budgeting, cost control, field-development planning, and project execution. He holds a Bachelor of Science degree in petroleum engineering from the University of the West Indies, a Doctor of Philosophy in chemical engineering, a Certificate of Strategic Management from the University of Calgary, and a Masters degree in business administration from Lansbridge University. Belgrave has also authored/co-authored numerous papers, reports, and conference presentations on air injection, which are frequently referenced internationally.
Scaleup of Effective Mass Transfer in Vapour-Extraction Process Accounting for Field-Scale Reservoir Heterogeneities presents a volume-averaging scheme to investigate the impacts of heterogeneity on the diffusion and mixing mechanisms encountered in vapour extraction (VAPEX). The conventional volume-averaging approach has been modified by using information from numerical fine-scale flow simulations. Results from the case study illustrate that mean and variance of effective-mass transfer coefficients vary with length scale, distance away from well pair, and pore volume injected. When recovery is compared with a fixed pore volume injected, it appears that heterogeneous features help improve the mass transfer because of dispersion by distorting the chamber edge with a larger interfacial contact area, allowing more time for mixing and maintaining a higher solvent concentration gradient across the interface.
Experimental Analysis of Heavy-Oil Recovery by Alternate Injection of Steam and Solvent (Hydrocarbon/CO2) in Unconsolidated Sand Reservoirs discusses the laboratory-scale application of a specific heavy-oil recovery method consisting of a successive injection of steam and different solvent gases (propane, butane, and carbon dioxide). The applied method is described along with the selection of parameters (e.g., temperature of steam, solvent soaking time, and solvent type). Optimal conditions that maximize the recovery of heavy oil and the retrieval of solvent in unconsolidated sand reservoirs are reported. A detailed comparative analysis of hydrocarbon solvents against carbon dioxide is provided.
Estimation of Effective-Fracture Volume Using Water Flowback and Production Data for Shale-Gas Wells discusses a new method that calculates effective-fracture volume using water-production data along with gas-production data. Procedures and examples for including water flowback and water-production data in the analysis of shale-gas wells are presented. A comparison between a number of simulation cases with field data using diagnostic and specialized plots is highlighted. Pitfalls of ignoring flowback data because of changes in the apparent flow regimes of early gas and water-production data are discussed.
Nonisothermal Artificial Lift
In a waxy-crude field using the gas-lift method, an innovative practice has been developed to sustain a high flowing temperature while heating up the flowing fluid by an electrical cable in tubing. By explicitly integrating energy conservation with the subsurface boundary conditions, our new algorithms in A Transient Two-phase Fluid and Heat Flow Model for Gas-lift Assisted Waxy Crude Wells with Periodical Electric Heating can optimize the cable length, heating strategy, supplied power, and gas-injection rate. This new method has been applied successfully in several wells. The power consumption has been noticeably reduced by 30%, comparing with historical field performance. The delegated optimization scheme curtails shut-in time in winters, which has promised cost-savings.