Executive Summary

Anil Ambastha, Chevron

With this issue, my 3-year term as an Executive Editor (EE) of SPE Res Eval & Eng (the Reservoir Engineering side of the journal) has come to an end. During these 3 years, I was involved in processing more than 800 papers through the editorial process. I read each one of these papers and their reviews to make as informed a decision on each manuscript as possible. It has been an incredible learning experience for me and I am grateful to the SPE for having provided me with this opportunity. I extend my personal thanks to all Associate Editors, Technical Editors, Authors, and SPE Staff for their excellent cooperation. Without such dedicated focus and assistance from all, I would not have succeeded in my job. Hopefully, our readers also agree that SPE Res Eval & Eng has continued to provide them with the best peer-reviewed articles of contemporary significance. This SPE mission to disseminate knowledge by means ofSPE Res Eval & Eng will, no doubt, continue in the future as I hand over the EE duties to my successor, Diederik van Batenburg. He is a reservoir engineer for Shell's enhanced-oil-recovery team in Rijswijk, The Netherlands. He joined Shell in 2006 after 13 years at Halliburton where he worked in research, operational, and management positions in the areas of well stimulation and water shutoff. van Batenburg holds MSc and PhD degrees in petroleum engineering from Delft University of Technology. Let’s all congratulate him on his selection as our next EE for SPE Res Eval & Eng (on the Reservoir Engineering side)!

In closing, as I say farewell to all of you, please note that if my actions/decisions offended any one of you, it was not intentional. I always tried to be as impartial, honest, and consistent as possible with respect to each manuscript. But to err is human and I hope that you would consider me worthy of your forgiveness for whatever you did not like about my actions and me.

Papers in this issue of the SPE Res Eval & Eng focus on shale/tight-gas reservoirs, carbonate reservoirs, seismic data integration, and advanced numerical techniques. The following is a brief outline of the papers in this issue primarily in authors’ words.

Shale and Tight-Gas Reservoirs

Maturity and Impedance Analysis of Organic-Rich Shales uses scanning acoustic microscopy to analyze and map the impedance microstructure in organic-rich shales (ORS). Textural properties in the images have been related to maturity and to impedance from acoustic wave propagation measured at cm scales. This combined study of acoustic and microstructures of ORS gives important insight in changes caused by kerogen maturation. Authors also discuss possible methods to predict maturity from impedance based on understanding the changes owing to maturity in well-log response, core measurements, and microstructure of ORS. Analysis of Data From the Barnett Shale Using Conventional Statistical and Virtual Intelligence Techniques analyzes Barnett Shale water production dataset from approximately 11,000 completions. Additionally, a water/hydrocarbon ratio and first derivative diagnostic plot technique developed elsewhere for conventional reservoirs is extended to analyze Barnett Shale water production mechanisms. To determine hidden structure in well and production data, self-organizing maps, and the k-means algorithm are used to identify clusters in data. A competitive learning based network has been used to predict the potential for continuous water production from a new well and a feed-forward neural network is used to predict average water production for wells drilled in Denton and Parker Counties of the Barnett Shale. Thermomagnetic Analyses of the Permeability-Controlling Minerals in Red and White Sandstones in Deep Tight Gas Reservoirs: Implications for Downhole Measurementsinvestigates the in-situ magnetic properties of deep tight gas reservoir samples (containing permeability-controlling reservoir minerals hematite and illite) by means of laboratory experiments to model downhole temperature conditions. Magnetic hysteresis measurements have been performed at various temperatures to (1) identify and quantify mineralogy and (2) model changes in the magnetic behavior of these minerals at in-situ downhole conditions. From these measurements, authors are able to show whether the mineralogy and/or domain state of the permeability-controlling minerals is likely to change with temperature in deep gas reservoirs. Petrophysics of Triple-Porosity Tight Gas Reservoirs With a Link to Gas Productivityshows that the sandstones are composed of intergranular, microfracture + slot, and isolated noneffective porosities based on petrographic work on thin sections from rock samples collected in tight gas sandstones of the Western Canada Sedimentary basin (WCSB). The petrographic observations of these triple-porosity rocks have led to a petrophysical interpretation with the use of a triple-porosity model. The petrography and core-calibrated triple-porosity model is then used for well-log interpretation of those wells where these data are not available. The result is a reasonable quantitative characterization of the tight gas reservoir that can be used for improving hydraulic fracturing design, flow units determination, reservoir engineering, and simulation studies.

Carbonate Reservoirs

Laboratory Investigation of the Impact of Injection-Water Salinity and Ionic Content on Oil Recovery From Carbonate Reservoirs presents a laboratory coreflooding study conducted using composite rock samples from a carbonate reservoir to investigate the impact of salinity and ionic composition on oil/brine/rock interactions and oil recovery. The experimental parameters and procedures were designed to reflect the reservoir conditions and current field injection practices, including reservoir pressure, reservoir temperature, salinity and ionic content of initial formation water and current types of injected water. The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the salinity and ionic content of field injected water. Also, nuclear-magnetic-resonance (NMR) measurements indicated that dilution of seawater can cause a significant alteration in the surface relaxation of the carbonate rock, and enhance connectivity among pore systems caused by rock dissolution. Electrokinetics of Limestone and Dolomite Rock Particles attempts to characterize the electrokinetics of limestone and dolomite suspensions at 25 and 50ºC. In addition, reaction mechanisms at the water/rock interface were established. Synthetic formation brine, seawater, and aquifer water were chosen from Middle East reservoirs. Carbonate particles were soaked in high- and low-salinity water. Phase-analysis light-scattering technique was used to determine the zeta potential (surface charge) of carbonate particles over a wide range of pH, ionic strength, and temperature.Electrokinetics of Limestone Particles and Crude-Oil Droplets in Saline Solutions studies the surface potential of crude oil and limestone particles at 50ºC. Ionic strength was varied using formation brine (230K ppm), seawater (54K ppm), shallow aquifer water (5K ppm), and fresh water. Two-phase (crude oil in water, limestone particles in water) and three-phase (crude oil and limestone particles in water) tests were performed at pH 8. The surface potential of oil droplets was strongly affected by 10 vol% diluted seawater, seawater without divalent ions (Ca2+ and Mg2+), and deionized water caused by the adsorption of OH– ions at the oil/water (O/W) interface. Sodium sulphate solutions (7,120 ppm) also increased the zeta potential absolute value of oil droplets. The effect of ionic strength on zeta potential was more pronounced in the oil-wet limestone particles than the intermediate-wet samples.

Seismic Data Integration

Preselection of Reservoir Models From a Geostatistics-Based Petrophysical Seismic Inversiondiscusses a matching process to identify reservoir models leading to acoustic responses close to the reference acoustic data. The parameterization of the facies and petrophysical properties populating the reservoir models is based upon the gradual deformation method which relies on geostatistical concepts. This particular feature makes it possible to change the spatial distribution of the property of interest from a few parameters while preserving its spatial variability. The matching process is driven from a global optimization algorithm known as the particle swarm optimization (PSO). A variant of the PSO algorithm is implemented to take advantage of the gradual deformation method properties. This approach yields reservoir models that honor the seismic data better than those derived from stochastic simulation only with seismic used as a secondary variable. Seismic History Matching of Nelson Using Time-Lapse Seismic Data: An Investigation of 4D Signature Normalization uses time-lapse (4D) seismic data from the Nelson field to detect production-induced changes as a complement to more conventional production data. In seismic history-matching, seismic data is predicted and compared to observations. Observed time-lapse data often consists of relative measures of change which requires normalization. Authors investigate different normalization approaches, based on predicted 4D data, and assess their impact on history matching.

Advanced Numerical Techniques

Near-Well-Subdomain Simulations for Accurate Inflow-Performance-Relationship Calculation To Improve Stability of Reservoir/Network Coupling proposes the calculation of multipoint inflow performance relationships (IPRs) obtained by solving near-well subdomains for the subsequent timestep. A flexible reservoir simulation architecture enables the dynamic creation and simulation of near-well subdomains at run time. These near-well subdomain simulations are embedded within the full-field simulation and extract all the required model properties (i.e., PVT, rock) from the full-field model. The most recent fluxes from the global solution are used as boundary conditions for the near-well subdomains. In this paper, the subdomain IPRs are used within reservoir-network coupling workflows for which traditionally-calculated IPRs result in oscillations and high errors.

As you study your favorite paper(s) to enhance your own knowledge and/or apply in your work activities, please recognize that SPE welcomes further discussion of any of the papers published in any SPE journal, including this one. Therefore, please feel free to submit discussion of a paper either online or by mail to SPE.

Anil Ambastha, Chevron