Let me start by discussing some news I personally find very exciting. Just before the summer, Equinor announced that the company gives the general public complete access to the subsurface and production data from the Volve field on the Norwegian Continental Shelf. The field was discovered in 1993 and is located 5 km north of the Sleipner Øst field. Since February 2008, Volve has produced a total of 63 million bbl of oil from sandstone in the Hugin Formation of the Jurassic age, reaching a recovery rate of 54% until the field was decommissioned in 2016. Equinor has obtained permission from its license partners ExxonMobil E&P Norway AS and Bayerngas Norge AS to release what is the complete data set from the Norwegian Continental Shelf. Altogether, the release represents data from many disciplines and includes geological and stratigraphical data, static and dynamic models, surface and grid data, well design, completion string design, seismic data, well logs, and production data.
Sharing data is very important to supporting education, research, and innovation, and I believe this data set will prove very useful for many readers of SPE Journal. Link to view and download the data (requires you to register): https://data-equinor-com.azurewebsites.net/authenticate.
This issue of SPE Journal brings you 24 papers categorized under six topics.
Zhang et al. discuss how transient swab/surge pressure during deepwater-drilling tipping and reaming can affect wellbore stability and present a model that can be used to determine safe windows for the drilling operation.
Frash and Carey develop an analytical model to study the potential for cement-annulus failure resulting from regional uplift or subsidence caused by injection and production. The authors also perform a sensitivity analysis to determine critical design parameters for ensuring annulus integrity.
Skorpa and Vrålstad study flow through cement sheaths that contain various types of degradation, from systematically connected cracks to microannuli. A computational-fluid-dynamics analysis using the Forchheimer equation is used to estimate permeability of cement sheaths with defects.
The paper by Schuetter et al. is a tutorial on how one can use statistical methods like random forests, support-vector regression, gradient boosting machine, and multidimensional kriging to build robust predictive models for oil production from shale reservoirs. The authors also discuss how one can develop decision rules that help identify factors separating good wells from poor performers.
Bassamzadeh and Ghanem study how one can use Bayesian networks to develop data-driven models for oil-production rate. The Bayesian network approach is applied to a data set from the Gulf of Mexico and compared with alternative predictions made by use of neural-network and co-kriging methods.
Zhang et al. develop a physics-based, data-driven model for history matching, prediction, and characterization of unconventional reservoirs. The basic idea is to reduce the 3D forward-flow model to a 1D model using a coordinate transformation given by a new diffusion diagnostic function, which is determined in a data-driven manner using an ensemble smoother method (ES-MDA).
Khaledialidusti and Kleppe discuss how pH changes induced by the hydrolysis of esters used in single-well chemical-tracer (SWCT) affect the shape of the observed tracer profiles and the numerical interpretation of field-test data for computing residual oil saturation. The effects are investigated using the combination of a multiphase flow simulator and a geochemistry package. The results of this study can be used to minimize uncertainties in SWCT tests and improve the reliability of measurements of residual saturation.
Behmanesh et al. present a seminanlytical model that can be used to analyze production data from wells exhibiting multiphase flow during boundary-dominated flow periods. The model is derived by combining material-balance equations with productivity index for all flowing phases.
Wang et al. present a new model developed to describe hydrate-blockage-formation behavior in testing tubing during deepwater-gas-well testing. They also show that inhibitors can delay the occurrence of hydrate blockage and that hydrate problems can be handled with smaller amounts of inhibitors during deepwater well-testing operations.
Zhan et al. describe a new reservoir-monitoring/testing tool that is better suited to obtain reliable estimates of the permeability distribution in ultratight and shale reservoirs. The tool generates multiple pressure pulses at targeted locations simultaneously along monitoring wells for zonal in-situ permeability estimation. A new simulation tool is used to analyze the pressure propagation and correctly account for potential interference effects.
Sheng et al. consider the use of dimethyl ether as an additive to steam for reducing the steam/oil ratio in steam-assisted gravity drainage (SAGD), while keeping SAGD-like rates of bitumen production. Numerical simulation shows that the chamber-edge temperature for a given composition and operating pressure will increase substantially if the solvent (ether) can partition into the aqueous phase at chamber-edge conditions and that using ether gives higher recovery factor than a corresponding alkane.
Irani provides field-supported results to illustrate the beneficial and potentially challenging impacts geomechanical effects can have in a thermal-recovery project. Measured displacements and identified dilation shear factors are compared with predictions from a Mohr-Coulomb dilative model.
Hu et al. propose a semianalytical model to predict the oil-flow rate resulting from combined electromagnetic heating and solvent-assisted gravity drainage. The authors conduct sensitivity analyses to examine the effect that major factors like EM heating powers, solvent type, and injection pressure have on recovery rates. The new model can be used to understand, design, and optimize this hybrid recovery technique.
Cha et al. present a laboratory study of cryogenic fracturing under true triaxial loading. The key concept of cryogenic fracturing is to create a sharp thermal gradient at the surface of the formation rock by applying a cryogenic fluid like liquid nitrogen, which will cause strong tensile stress and initiate fractures. Results show that stimulation by liquid nitrogen clearly increases permeability and that the breakdown pressure is significantly reduced (up to 40%).
Fan et al. use a combination of a discrete-element method and lattice Boltzmann simulation to better understand the interaction between reservoir depletion, compaction of proppant particles, and single- and multiphase flow in hydraulic fractures. The authors compute the effective permeability of the proppant pack as a function of applied stress and study the effect of proppant-size heterogeneity. They also compute relative permeability curves and show that the curves for the oil phase are more sensitive to changes in geometry and stress, compared with the wetting phase.
Mittal et al. study measurement of long-term conductivity of proppant packs. Various impairment mechanisms like proppant crushing, fines migration, embedment, and diagenesis are investigated.
Al-Rbeawi uses bivariate log-normal distributions to investigate the impact of stimulated matrix permeability and matrix-block size on pressure behavior and flow regimes in hydraulically fractured reservoirs. To this end, the author uses a number of analytical models for pressure responses, assuming rectangular drainage areas.
Karimi and Kazemi present a comprehensive series of experiments to determine the flow properties of 12 Middel Bakken cores. Experiments include centrifuge, mercury-intrusion capillary pressure, nitrogen adsorption, nuclear magnetic resonance, and resistivity, from which the authors could determine irreducible saturations, mobile-fluid-saturation range for water displacing oil and gas displacing oil, pore-size distribution, and tortuosity.
Tahmasebi et al. discuss geologic modeling of mudrock reservoirs. Using high-resolution panoramic outcrop images, the authors collect data on lithofacies heterogeneity and the role that the depositional processes play in this heterogeneity. The data are then used with two-point, object-based, and higher-order statistics methods to build a geologic model. The approach is demonstrated using Eagle Ford outcrops from west Texas.
Guo et al. use a fully coupled multiphase and rock deformation model to accurately characterize pressure distribution and update stress states through history matching production data of parent wells in Eagle Ford shale. This way, the authors investigate how depletion of parent wells with complex fracture geometry impacts stress states, and analyze stimulation efficiency of infill wells. Results show that the magnitude and orientation of principal stresses are greatly altered by depletion and that the alteration is uneven because of nonuniform fracture geometries.
One of the main production recovery mechanisms in unconventional reservoirs is the flow exchange between matrix and fractures. This exchange can be very slow for reservoirs with very low matrix permeability. Conventional dual-porosity (DP) models fail to accurately resolve this effect, especially for multiphase flow with phase change. To overcome this limitation, Ding et al. present an embedded-discrete-fracture model (EDFM) that depends on the multiple-interaction-continua (MINC) function.
Yan et al. proposes an adaptive hybrid model to simulate hydromechanical coupling processes in fractured shale reservoirs during production. The hybrid approach assumes a single-porosity model in the region outside the stimulated reservoir volume, the matrix and natural/induced fractures inside the stimulated region are modeled with a double-porosity model, whereas hydraulic fractures are modeled explicitly with the EDFM. The flow model is discretized by a finite-volume method, whereas the mechanical process is discretized by a stabilized extended finite-element method (XFEM) with a polynomial-pressure-projection technique.
Neshat et al. discuss the phase behavior of hydrocarbon mixtures in tight and shale formations. The authors integrate several important thermodynamic and petrophysical aspect in a rigorous way, introduce a solution that can be used over a wide range of pore sizes, and use a novel three-phase capillary-pressure model to estimate the effect of connate water on the gas/oil capillary pressure. The new method is applied to examples of binary and multicomponent reservoir fluids.
Jia et al. study transport mechanisms for CO2 in shale reservoirs under a wide pressure range using pressure-pulse-transmission tests with helium and nitrogen for reference. The results indicate that helium permeability is the highest among the three and that the petrophysical characteristics of CO2 differ from the other two.
I wish to thank all who have written, reviewed, copy-edited, and prepared the papers in this issue.
Knut-Andreas Lie, SPE J. Executive Editor,