The four papers in this month’s issue cover a diverse range in challenges in our industry and will enlighten readers on the subjects of in-situ scale deposition control for applications employing seawater injection, employing stingers to improve horizontal well inflow distribution, enhancements to pressure transient analysis of unconventional wells, and laboratory testing of a next-generation recovery process for heavy oil.
In the paper entitled Evaluating the Damage Caused by Calcium Sulfate Scale Precipitation During Low- and High-Salinity-Water Injection, Mohamed Ahmed Nasr El-Din Mahmoud of the King Fahd University of Petroleum and Minerals addresses the complexities of managing scale precipitation associated with the injection of seawater into formations where the injected water is incompatible with the formation brine. The introductory section of the paper provides an excellent subject matter review; therefore, the paper is comprehensible and informative for a broad range of readers. The reader is introduced to the basic mechanisms by which and conditions under which various forms of scale can be precipitated in reservoirs. Methods for preventing, controlling, and remedying in-situ scale deposition are also discussed. The paper then presents the results of a series of experiments using Berea sandstone cores to illustrate the porosity and permeability damage that can result from incompatible water injection. Experimental results demonstrate the effectiveness of continuous injection of different chelating agents (e.g., ethylene diamine tetra acetic acid, hydroxyl ethylene diamine triacetic acid, and hydroxy ethyl imino diacetic acid for managing and remediating the impacts of in-situ scale deposition. The paper also develops some simple analytical models that match the observed processes and can be used to aid in extrapolating the results to the field scale.
Controlling the inflow profile along horizontal wells is an important challenge for many conventional and unconventional reservoirs. One relatively simple method of retrofitting existing wells is to modify the well’s completion by installing a stinger completion that in effect moves or redistributes the inflow points for production tubing. In the paper A Semianalytical Model for Horizontal Wells With Improved Stinger Completion in Heterogeneous Bottomwater Reservoirs, Haitao Li, Beibei Jiang , Yongqing Wang, Junchao Wang, and Shasha Jiang from the Southwest Petroleum University in Chengdu, China, present the development of a model that combines analytical and finite-difference methods to solve the fluid inflow distribution along an undulating horizontal well with heterogeneous reservoir parameters and different stinger completion designs. While few readers will replicate the development of this numerical model, after reading the paper, one will have an appreciation of the key physical parameters that need to be considered in the design of stinger completions. The authors illustrate the usage of the model through a field example from the Luliang oil field.
Advances in multistage hydraulic fracturing methods have been a game changer for the development of unconventional reservoirs and concomitantly new methods for better interpreting pressure measurements acquired during the processes are emerging. In collaborative effort between Bahareh Nojabaei of Pennsylvania State University, A. Rashid Hasan of Texas A&M University, and C. Shah Kabir of Hess Corporation, the paper Modelling Wellbore Transient Fluid Temperature and Pressure During Diagnostic Fracture-Injection Testing in Unconventional Reservoirs introduces a relatively simple method for assessing the potential impact of thermal wellbore transients. Diagnostic fracture-injection testing can be employed to determine critical reservoir parameters such as the minimum in-situ stress, reservoir pressure, and reservoir permeability. However, given the low permeability of the formation, relatively large volumes of the wellbores, and potential temperature changes in the wellbore fluids as the temperatures equilibrate after a shut-in, corrections may need to be applied to surface-measured pressures. The analyses provided in the paper provide appropriate methodologies for determining when temperature effects need to be considered and corrections applied. The application of the methods to field examples from the Bakken and the Eagle Ford along with the associated discussion highlight how fracture-pressure analysis continues to be a mix of pragmatism, heuristics, and theory.
The paper entitled Effect of Dead-Oil Viscosity and Injected-Solvent Type on SVX Process Performance presents a series of physical model experiments of a solvent-vapour-extraction (SVX) process. The paper is authored by Kelly Knorr and Muhammad Imran of the Saskatchewan Research Council. The process is in the same class as the vapour extraction process, which has been described extensively by Roger Butler and his colleagues. Rather than injecting steam or steam-solvent fluids to mobilize heavy oil, cold solvents (e.g., light alkanes or carbon dioxide) are injected into the model. The attraction of this class of processes is much improved environmental performance when compared with thermal processes as measured by both greenhouse-gas emissions and water usage. While it is difficult to scale the model setup and process to a practical field configuration, it does provide some useful insights. The experiments have been performed with mixtures of methane and propane or carbon dioxide and propane. The latter is shown to have the better overall performance. The initial in-situ oil viscosity is also shown to have an impact on results and, as one might expect, higher-viscosity oils present more challenges for recovery. The ultimate recoveries from the models are in the 30 to 40% of initial oil in place, which demonstrates that the SVX process does have future potential.
T. J. (Tom) Boone, Ph.D., P.Eng.
Tom Boone is currently ExxonMobil’s senior reservoir consultant for improved oil recovery (IOR) and enhanced oil recovery (EOR), based out of Calgary. Before this appointment, he was Imperial Oil Resources’ manager for oil-sands recovery research at Imperial’s research laboratory in Calgary. Boone has more than 25 years of experience with ExxonMobil and Imperial Oil, where he has developed specialized expertise in geomechanics, heavy-oil recovery processes, reservoir engineering, reservoir simulation, and field development. During Boone’s career, he has held positions in Calgary, Houston, and Stavanger, Norway. Boone holds a PhD degree from Cornell University, an MSc degree from The University of Texas at Austin, and a BASc degree from the University of Waterloo, all in civil or structural engineering.
Evaluating the Damage Caused by Calcium Sulfate Scale Precipitation During Low- and High-Salinity-Water Injection discusses the deposition of the calcium sulfate scale during low- and high-salinity water injection using coreflooding experiments. The damage was quantified using material-balance and computed-tomography scan techniques. A new technique, which includes the injection of hydroxyl ethylene diamine triacetic acid, ethylene diamine tetra acetic acid, or hydroxy ethyl imino diacetic acid chelating agents with the water, was introduced to prevent the damage caused by calcium sulfate scale. The damage caused by calcium sulfate in real field scale was predicted using material-balance and analytical solutions and the prediction was a good match with the experimental and field data. The effect of pore-throat size distribution through the core was found to impact the damage distribution along the core.
A Semianalytical Model for Horizontal Wells With Improved Stinger Completion in Heterogeneous Bottomwater Reservoirs discusses the detailed derivation and field application of a semianalytical model for horizontal wells with improved stinger completion (ISC) in bottomwater reservoirs. The detailed solution of the semianalytical model is given. The steps for the optimization design of ISC and principles for choosing target wells are summarized, which is crucial for achieving good water-control results by using the new semianalytical model in a bottomwater reservoir. The new method is of easy operation and low cost and can be applied to horizontal wells with low production, deep depth, and multibranches in a bottomwater reservoir.
Modelling Wellbore Transient Fluid Temperature and Pressure During Diagnostic Fracture-Injection Testing in Unconventional Reservoirs presents a transient wellbore-heat-transfer model for translating wellhead pressure (WHP) into bottomhole pressure (BHP) when a large volume of water injection occurs. To this end, the study presents an analytical model for temperature transients that allows for the evaluation of water density, compressibility, and thermal expansion at each depth step for evaluating BHP. In other words, this study explores the question of whether a constant hydrostatic head correction to the WHP suffices during the falloff period. Generally speaking, if the fracture closure occurs within 10 hours in a setting where considerable injection occurs, then temperature modelling is needed for pressure correction; otherwise, hydrostatic-head correction suffices. A fluid-temperature model during injection also allows rigorous determination of BHP for the analysis of injection data (e.g., with the modified Hall method). In this regard, a new semianalytical formulation of the modified Hall method allows rigorous treatment of injection data involving linear flow. The plot suggests that the linear flow is short-lived and the dominant mechanism appears to be fluid storage within the fracture, given high-rate injection over a short time span.
Effect of Dead-Oil Viscosity and Injected-Solvent Type on SVX Process Performance presents experimental results of four 3D physical model experiments that were performed to evaluate the effect of dead-oil viscosity and injected solvent type on SVX process performance. Model excavation studies were also performed to approximate the solvent movement in the physical model and to map out the residual oil saturation and precipitated asphaltenes. This study revealed that higher oil-production rates can be achieved with the lower-viscosity oils for both injected-solvent-mixtures types, with a more-pronounced effect observed when using the CO2/C3 solvent mixture. This study also showed that the CO2/C3 mixture resulted in earlier solvent breakthrough and initial oil production, reduced solvent makeup requirements, and reduced solvent retention in the model/reservoir, as compared with the C1/C3 solvent mixture. The residual-oil-saturation mapping showed that the CO2/C3 mixture led to comparatively lower values in the drained region and a higher amount of precipitated asphaltenes in the model. This mapping also indicated that the solvent/oil interfaces and solvent chambers were more uniform and predictable for the CO2/C3 solvent-mixture injection.