With this issue, I have the honor of taking the Formation Evaluation Executive Editor position from Alan Johnson. We are grateful for his contributions in a period of increased activity, meetings, and reviews. Alan and his team coped with the changes quite well, while keeping the quality of the journal as the main focus. The total number of manuscripts (new and revised) for SPEREE was 380 in 2005, and it jumped to 770 in 2007. The Editorial Review Committee for our journal had to make close to 1,000 decisions last year; 113 papers were accepted for publication, and 68 were published. While the fraction of accepted papers has remained somewhat stable across the years, the sheer increase in numbers put a greater strain on the review teams. Last year, the team felt the pressure and our journal’s teams went through significant efforts to increase the number of technical editors and review chairs, thanks to Behrooz Fattahi’s initiatives. The formation evaluation side of SPEREE now has 10 review chairs: David Larue, Dimitrios Hatzignatou, Omar Varela, Douglas Schmitt, Allyson Gajraj, Patrick Egermann, James Sheng, Steve Crary, Marc Hattema, and Michael Webster. With the increasing number of geomechanics papers, a team of experts is now in place. For comparison, the number of technical editors for the formation evaluation side, who are the backbone of the whole process, increased to 210 in 2007 from 122 in 2005.
I have been in the oil industry since 1981, when I received my undergraduate degree. Ten years later, I started as a Technical Editor and have been one since then. Serving on the Editorial Review Committee as a volunteer has its merits; it is fulfilling to be a part of the process of collecting and disseminating technical knowledge and recent advances. Finding SPE papers from library proceedings and microfiches seems like the distant past, but as a student I perhaps did not realize how important it was to access quality technical information with relative ease. This notion of finding the latest advances and making use of it in education, research, and in day-to-day operations is still there, and is helping the industry advance worldwide. It is worth mentioning that my 16 years of service on the Editorial Review Committee has not only forced me to keep up with the advancing technology, but has also required an extra time allocation for this task in return.
In this issue, we have a variety of topics ranging from recent advances in fluid sampling to revisiting techniques to estimate average reservoir pressure. The article “Focused Sampling of Reservoir Fluids Achieves Undetectable Levels of Contamination” describes a new focused probe to obtain fluid samples with very-low or below-detectable levels of mud-filtrate contamination using a wireline formation tester. In a related paper, “Compositional Modeling of Oil-Based-Mud-Filtrate Cleanup During Wireline-Formation-Tester Sampling,” the issue of obtaining a representative hydrocarbon sample in wells drilled with oil-based mud is discussed, with the authors using compositional simulation to investigate the cleanup behavior of a wireline-formation-tester pumpout process. The study covered pumpout through a probe, and the cleanup dependency was found to closely follow the empirical time relationship currently used to monitor the sampling process at the wellsite. Continuing with wireline formation testing, the paper“Hydrocarbon Compositional Gradient Revealed By In-Situ Optical Spectroscopy” gives an example of compositional gradients in a relatively thin reservoir, identified by analyzing fluids downhole at several stations by use of visible and near-infrared spectroscopy. Identifying fluids using nuclear magnetic resonance (NMR) in carbonate formations was discussed in the paper “Use of the NMR Diffusivity Log To Identify and Quantify Oil and Water in Carbonate Formations.” Using diffusion logs and maps constructed from 2D NMR interpretation, oil and water zones were identified where relaxation times of water and oil did not show significant contrast and the diffusivity of oil and water were partially overlapping. Estimating fluid properties is one task almost all of us have encountered a few times—and some almost daily. The paper “An Accurate Method for Determining Oil Pressure/Volume/Temperature Properties Using the Standing-Katz Gas Z-Factor Chart” treats oil molecular weight as the primary correlating factor and outlines a method to determine oil PVT properties making use of the well known gas z-factor charts. In the area of well testing and fluid flow in porous media, layered reservoirs with crossflow are investigated in the paper “Estimation of Storativity Ratio in a Layered Reservoir With Crossflow.” The paper uses the separation between the two semilog straight lines observed in dual-permeability reservoirs to estimate the storativity ratio, since this separation for such systems is known to be a function of both storativity and transmissivity ratios. Non-Darcy flow is revisited in the paper “Semianalytical Model for Reservoirs With Forchheimer’s Non-Darcy Flow,” where inertial-turbulent effects are considered near the wellbore and in the reservoir. The effects are different for drawdown and buildup, as investigated for a vertical well during radial flow in a homogeneous formation. Drawdown derivatives show a longer transition from storage-dominated flow to radial flow, whereas buildups have a much steeper transition. With more experience in underbalanced drilling, the efforts to estimate formation properties from drilling data are increasing, as discussed in the paper “Simulation of Inflow While Underbalanced Drilling With Automatic Identification of Formation Parameters and Assessment of Uncertainty.” The paper shows the use of a multiphase numerical model with a time-variant underbalanced-drilling boundary condition in a heterogeneous system. The inflow information is used to determine formation properties, also incorporating associated uncertainties. Many reservoir engineers will remember the Muskat plot to estimate average reservoir pressure with its upward and downward bends. The paper “A New Method for Estimating Average Reservoir Pressure: The Muskat Plot Revisited” brings a new look at this old technique for simple homogeneous and heterogeneous systems. Recent advances in technology made oil and gas industry focus more on geomechanics in cases where reservoir performance depends significantly on how the rock behaves under changing stress conditions. The paper “Effect of Fracture Compressibility on Gas-in-Place Calculations of Stress-Sensitive Naturally Fractured Reservoirs” shows that ignoring the fracture and matrix compressibility during material-balance computations in which stress dependency is significant may cause optimistic estimates of original gas in place. Modern production-data analysis using material-balance, time, and pseudopressure has been extended for coalbed-methane (CBM) reservoirs in the paper “Production-Data Analysis of CBM Wells.” The authors consider CBM reservoirs with single-phase gas, single-phase water, and gas-plus-water flow, examining changes in gas composition and effective permeabilities with depletion. Production optimization is studied in the paper “Production Optimization With Adjoint Models Under Nonlinear Control-State Path Inequality Constraints.” The authors propose an approximate feasible direction nonlinear programming algorithm on the basis of the objective-function gradient and a combined gradient of the active constraints. The method presented requires only two adjoint evaluations at each iteration, and large step sizes are possible during the line search, which may lead to significant gains in computational efficiency. Considerable research is under way to investigate and quantify risks in many aspects of applied reservoir engineering. In this issue, quite a few papers focus on uncertainty and risk. In the paper “Quantifying Resources for the Surmont Lease With 2D Mapping and Multivariate Statistics,” a 2D geostatistical-modeling process is outlined to characterize the reservoir quality of the McMurray formation, which consists of heterogeneous Cretaceous bitumen-saturated sands. Geological risks in exploration settings are investigated in “Modeling Dependence Among Geologic Risks in Sequential Exploration Decisions.” The paper describes a methodology for modeling dependence among prospects and determining an optimal drilling strategy that takes this information into account. In another paper, titled “Application of Integrated Reservoir Studies and Probabilistic Techniques to Estimate Oil Volumes and Recovery, Tengiz Field, Republic of Kazakhstan,” the authors outline Monte Carlo simulation and experimental design techniques to identify key static and dynamic parameters. Probabilistic distribution of oil in place and recoveries are outlined; oil in place, gas/oil relative permeability, and vertical/horizontal-permeability ratio are found to have a significant impact on the estimated oil recoveries. In the paper “Partial Probabilistic Addition: A Practical Approach for Aggregating Gas Resources,” the authors discuss the risks associated with a liquefied-natural-gas plant project supplied from multiple hydrocarbons sources. The problem of incorporating risks associated with each reservoir as a project-level aggregate is discussed. Injection/production-pattern performance results from classical surveillance methods (on the basis of fixed-well patterns) are compared with a streamline surveillance model that uses flow-based well-rate allocation factors in the paper “Revisiting Reservoir Flood-Surveillance Methods Using Streamlines.” Oil potential downdip in a carbonate reservoir is investigated in the paper“Downdip-Oil Potential for an Onshore Abu Dhabi Petroleum System.” A combination of fluid inclusion and geochemical analyses is conducted for an improved understanding of downdip-oil potential in a mature exploration area. In one of the examples, the possibility of undiscovered downdip oil is identified. Steady-state upscaling techniques for multiphase flow are attractive, since they are fast and relatively easy to implement. In the paper “Validity of Steady-State Upscaling Techniques,” the authors give quantitative criteria to determine the validity of steady-state methods and when capillary or viscous forces dominate the process for heterogeneous systems. In reservoirs with intermediate-scale heterogeneity, the authors state the validity of the capillary-limit method is restricted to very small production rates, which are unlikely to be encountered in most production scenarios. Optimum recovery strategies for naturally fractured reservoirs are studied in the paper “Primary and Secondary Oil Recovery From Different-Wettability Rocks by Countercurrent Diffusion and Spontaneous Imbibition,” using coreflood experiments. Different wettabilities and rock types are considered, testing two different strategies: primary countercurrent spontaneous imbibition followed by secondary recovery with the diffusion of a miscible phase and primary diffusion of a miscible fluid without preflush of matrix by spontaneous imbibition.