Abstract: Millimeter-sized (10 um~mm) preformed particle gels (PPGs) have been used successfully as conformance control agents in more than 5,000 wells. They help to control both water and CO2 production through high-permeability streaks or conduits (large pore openings), which naturally exist or are aggravated either by mineral solutions or by a high injection pressure during the flooding process. This paper explores several factors that can have an important impact on the injectivity and plugging efficiency of PPGs in these conduits. Extensive experiments were conducted to examine the effect of the conduit’s opening size and the PPG strength on the ratio of the particle size to the opening diameter, injectivity index, resistance factor, and plugging efficiency. Five-foot tubes with four internal diameters were designed to emulate the opening conduits. Three pressure taps were mounted along the tubes to monitor PPG transport and plugging performance. The results show that weak gel has less injection pressure at a large particle opening ratio compared to strong gel. PPG strength impacted injectivity more significantly than did particle opening ratio. Resistance factor increased as the brine concentration and conduit opening size increased. PPGs can significantly reduce the permeability of an open conduit and their plugging efficiency depends highly on the particle strength and the conduit’s opening size. The particle size of PPG was reduced during their transport through conduits. Experimental results confirm that the size reduction was caused by both dehydration and breakdown. Based on the lab data, two mathematical models were developed to quantitatively calculate the resistance factor and the stable injection pressure as a function of the particle strength, particle opening ratio, and shear rate. This research provides significant insight into designing better millimeter-sized particle gel treatments intended for use in large openings, including open fractures, caves, worm holes, and conduits. Introduction Excess water production in oil fields is becoming a challenging economical and environmental problem as more reservoirs are maturing. An estimated average of three barrels of water are produced for each barrel of oil produced worldwide (Bailey et al., 2000). It is estimated that the total cost to separate, treat, and dispose of this water is approximately $50 billion per year (Hill et al., 2012). Water can flow into the wellbore as a result of either near-wellbore problems or reservoirrelated problems (Seright et al., 2001). The mechanisms that contribute to this undesired water production must be fully understood before the appropriate treatment can be chosen. Water channeling, one of the primary reservoir conformance problems, is caused by reservoir heterogeneities that lead to the development of high-permeability streaks. These streaks include open fractures and fracture like features, such as caves, worm holes, and conduits (Smith et al, 2006). These highconductivity areas inside the reservoir only occupy a small fraction of the reservoir but will capture a significant portion of injected water. As a result, large amounts of oil remain unswept as a large water flood will bypass oil-rich unswept zones/areas. Gel treatments have been proven to be a cost-effective chemical conformance control technology to reduce the fluid flow in these large opening features. The application of these technologies can not only control water production but also significantly increase the oil production and extend the economic life of a reservoir. Traditionally, in-situ bulk gels have been used for this purpose. However, preformed particle gels recently have attracted much attention because they can solve some of the problems associated with in-situ gel systems, such as the dilution and dispersion of the gelant, chromatographic separation of the gelant solution, and so on. (Chauveteau et al., 2001, 2003; Coste et al., 2000; Bai et al., 2007a, 2007b).

Abstract: Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5–30% original oil in place (OOIP) in coreflooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil-wet or mixed-wet to morewater-wet conditions. Modeling of wettability-alteration experiments, however, is challenging because of the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase and multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggest that desorption of acidicoil components from rock surfaces make carbonate rocks more water-wet. One widely accepted mechanism is that sulfate (SO 4 ) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca2þ, Mg2þ) decrease the oil-surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional untuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of more than 40% OOIP, whereas cations such as Ca2þ have a relatively minor effect on recovery (approximately 5% OOIP). Physical parameters, including the total surface area of the rock and the diffusion coefficients, control the rate of recovery, but not the final oil recovery. The simulation results further demonstrate that the optimum brine formulations for chalk are those with relatively abundant SO 4 (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength of less than 0.2 mol/ kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios. To the best of our knowledge, this is the first model that explicitly and mechanistically couples multiphase flow and multicomponent surface complexation with wettability alteration and oil recovery for carbonate rocks specifically.

Abstract: In this work, we develop and apply a general methodology for optimal closed-loop field development (CLFD) under geological uncertainty. CLFD involves three major steps: optimizing the field-development plan on the basis of current geological knowledge; drilling new wells, and collecting hard data and production data; and updating multiple geological models on the basis of all the available data. In the optimization step, the number, type, locations, and controls for new wells (and future controls for existing wells) are optimized with a hybrid particle swarm optimization-mesh adaptive direct search algorithm. The objective here is to maximize expected (over multiple realizations) net present value (NPV) of the overall project. History matching is accomplished with an adjoint-gradient-based “randomized maximum likelihood” procedure. Because the CLFD history-matching component is fast relative to the optimization component, we generate a relatively large number of history-matched models. Optimization is then performed with a set of “representative” realizations selected from the full set of history-matched models. We introduce a systematic optimization with sample validation (OSV) procedure, in which the number of realizations used for optimization is increased if an appropriate validation criterion is not satisfied. The CLFD methodology is applied to 2D and 3D example cases. Results show that the use of CLFD increases the NPV for the “true” (synthetic) model by 10 to 70% relative to that achieved by optimizing over a large number of prior realizations. We also compare the results for CLFD with OSV to results that use a fixed number of geological realizations. These comparisons show that the use of too few realizations in the CLFD optimization step can result in lower true-model NPVs, whereas OSV provides a systematic approach for determining the proper number of realizations.

Abstract: Lost circulation, a major complication of drilling operations, is commonly treated by adding materials of various types, shapes, and particle-size distributions to the drilling mud. Generally known as wellbore strengthening, this technique often helps the operator to drill with higher mud gradients compared with that suggested by the conventional fracture-gradient or borehole-fracture-limit analysis. The underlying mechanisms through which a wellbore is strengthened, however, are not yet fully understood. This study explores these wellbore-strengthening mechanisms through an analytical solution to the related solid-mechanics model of the wellbore and its adjacent fractures. The provided solution is generic in that it takes into account the mechanical interaction of multiple fractures between one another and the wellbore under an arbitrary state of in-situ stress anisotropy. An additional generality in this solution arises from its unification and quantification of some solid-mechanics aspects of the previous hypotheses that have been published on the subject—i.e., stress cage, as well as the tip isolation and its effect on the fracture-propagation resistance. In relation to the stress-cage theory, the study investigates the wellbore-hoop-stress enhancement upon fracturing. The findings indicate that the induced hoop stress is significant at some regions near the wellbore, especially in the general vicinity of the fracture(s). However, given the strong dependency of wellbore stress on the mechanical and geometrical parameters of the problem, generalizing these results to the entire region around the wellbore may not always be trivial. The study also examines tip isolation, a common feature of fracture-closure and propagation-resistance hypotheses, through the analysis of partially reduced fracture pressures and a breakdown criterion, defined by the critical stressintensity factor of the formation rock.

Abstract: This paper describes an experimental study of the stability of a hydrolyzed polyacrylamide (HPAM) polymer and an HPAM-2acrylamido-tertbutylsulfonic acid (ATBS) terpolymer in the presence of varying initial levels of dissolved oxygen (0 to 8,000 ppb), Fe2þ (0 to 220 ppm), and Fe3þ (0 to 172 ppm). A special method was developed to attain and confirm dissolved-oxygen levels. Stability studies were performed at 23 and 90 C. For Fe2þ concentrations between 0 and 30 ppm, viscosity losses were insignificant after 1 week when the initial dissolved oxygen concentration was 200 ppb or less. Above this level, significant viscosity losses were seen, especially if iron was present. If the temperature is high, a greater need arises to strive for very low dissolved-oxygen content. For samples stored for 1 week at 90 C with only 10-ppb initial dissolved oxygen, contact with steel caused HPAM-ATBS solution viscosity losses greater than 30%. In contrast at 23 C, contact with steel caused no significant degradation when the dissolved O2 concentration was 1,000 ppb or less. Several different methods are discussed to control oxidative degradation of polymers during field applications. We advocate physical means of excluding oxygen (e.g., stopping leaks, better design of fluid transfer, gas-blanketing, gas-stripping) rather than chemical means. Addition of Fe3þ to polymer solutions caused immediate crosslinking. Because crosslinked polymers were never observed during our studies with Fe2þ, we conclude that free Fe3þ was not generated in sufficient quantities to form a visible gel.

Abstract: This paper presents experimental observations that delineate co-optimization of carbon dioxide (CO2) enhanced oil recovery (EOR) and storage. Pure supercritical CO2 is injected into a homogeneous outcrop sandstone sample saturated with oil and immobile water under various miscibility conditions. A mixture of hexane and decane is used for the oil phase. Experiments are run at 70 degrees C and three different pressures (1,300, 1,700, and 2,100 psi). Each pressure is determined by use of a pressure/volume/temperature simulator to create immiscible, near-miscible, and miscible displacements. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil is defined and calculated using the measured data for each experiment. A compositional reservoir simulator is then used to examine gravity effects on displacements and to derive relative permeabilities.Experimental observations demonstrate that almost similar oil recovery is achieved during miscible and near-miscible displacements whereas approximately 18% less recovery is recorded in the immiscible displacement. More heavy component (decane) is recovered in the miscible and near-miscible displacements than in the immiscible displacement. The co-optimization function suggests that the near-miscible displacement yields the highest CO(2)storage efficiency and displays the best performance for coupling CO2 EOR and storage. Numerical simulations show that, even on the laboratory scale, there are significant gravity effects in the near-miscible and miscible displacements. It is revealed that the near-miscible and miscible recoveries depend strongly on the endpoint effective CO2 permeability.

Abstract: Fracture distributions (simple or complex fractures), fracture-conductivity heterogeneity (uniform or varying conductivity along the fracture), and flow regimes inside the fracture (Darcy or nonDarcy flow) are the three main issues that have been widely investigated for transient-pressure analysis of vertical fracture systems. In this study, we focus on the latter two issues by proposing a semianalytical solution to discuss the transient-pressure behaviors of a varying-conductivity fracture under non-Darcy-flow condition. First, a general fracture-flow equation is established for the uniform-/varying-conductivity fracture under Darcy/non-Darcy flow. Second, for the case of a varying-conductivity fracture, a dimension transformation and an unequal-length-discretization model are proposed to obtain the pressure solution. Then, the transient-pressure response for the case of non-Darcy flow in the fracture can be also obtained by use of an iterative procedure in each timestep in the Laplace domain. It is shown that results from our solutions agree very well with those reported in the literature (Guppy et al. 1982; Poe et al. 1992). Third, the transient-pressure behaviors of the varying-conductivity fracture under Darcyand non-Darcy-flow condition are discussed in detail. Results show that non-Darcy flow in the fracture mainly reduces the effective conductivity and the transient-pressure curve follows the curve of an equivalently constant conductivity except for the case of extremely small conductivities. The pressure behaviors of varying-conductivity fractures depend on the value of average conductivity, the distribution of conductivity along the fracture, and the maximum-minimum-conductivity ratio. The presence of the varying conductivity not only affects the effective conductivity in the early and late times, but also changes the shape of the pressure curve, especially for the high-conductivity fracture in the early time. It is very difficult to accurately estimate the fracture parameters by well test for most of the cases of varying conductivities under non-Darcy flow in the fracture.

Abstract: Industrial consortium in Reservoir Simulation and Modelling; Foundation CMG; Alberta Innovates.

Abstract: Various logging-while-drilling (LWD) and seismic-while-drilling (SWD) tools offer opportunities to obtain geological information near the bottom-hole-assembly during the drilling process. These real-time in-situ data provide relatively high-resolution information around and possibly ahead of the drilling path compared to the data from a surface seismic survey. The use of this in-situ data offers substantial potential for improved recovery through continuous optimization of the remaining well path while drilling. We show an automated workflow for proactive geosteering through continuous updating of the estimates of the earth model and robust optimization of the remaining well path under uncertainty. A synthetic example is shown to illustrate the proposed workflow. The estimate of the reservoir surfaces, reservoir thickness, and the depth of the initial oil-water contact and their associated uncertainty are obtained through the ensemble Kalman filter using directional resistivity measurements. A robust optimization is used to compute the well position that minimizes the average cost function evaluated on the ensemble of geological models estimated from the EnKF.