Showing papers in "Spe Journal in 2017"

How Much Polymer Should Be Injected During a Polymer Flood? Review of Previous and Current Practices

Abstract: This paper provides an extensive review of the polymer concentrations, viscosities, and bank sizes used during existing and previous polymer floods. On average, these values have been substantially greater during the past 25 years than during the first 30 years of polymer flooding field activity. Reasons for the changes are discussed. Even with current floods, a broad range of polymer viscosities are injected—with substantial variations from a base-case design procedure. Extensive discussions with operators and designers of current polymer floods revealed substantial differences of opinion for the optimum design of polymer floods. This paper examines the validity of arguments that are commonly given to justify deviations from the base-case design. For applications involving viscous oils (e.g., 1000 cp), the designed polymer viscosities have sometimes been underestimated because of (1) insufficient water injection while determining relative permeabilities, (2) reliance on mobility ratios at a calculated shock front, and (3) over-estimation of polymer resistance factors and residual resistance factors. In homogeneous reservoirs, the ratio of produced oil value to injected fluid cost is fairly insensitive to injected polymer viscosity (up to the viscosity predicted by the base-case method), especially at low oil prices. However, reservoir heterogeneity and economics of scale associated with the polymer dissolution equipment favor high polymer viscosities over low polymer viscosities, if injectivity is not limiting. Injection above the formation parting pressure and fracture extension are crucial to achieving acceptable injectivity for many polymer floods—especially those using vertical injectors. Under the proper circumstances, this process can increase fluid injectivity, oil productivity, and reservoir sweep efficiency, and also reduce the risk of mechanical degradation for polyacrylamide solutions. The key is to understand the degree of fracture extension for a given set of injection conditions so that fractures do not extend out of the target zone or cause severe channeling. Many field cases exist with no evidence that fractures caused severe polymer channeling or breaching the reservoir seals, in spite of injection above the formation parting pressure. Although at least one case exists (Daqing) where injection of very viscous polymer solutions (i.e., more viscous than the base-case design) reduced Sor below that for waterflooding, our understanding of when and how this occurs is in its infancy. At this point, use of polymers to reduce Sor must be investigated experimentally on a case-by-case basis. A “one-size-fits-all” formula cannot be expected for the optimum bank size. However, experience and technical considerations favor using the largest practical polymer bank. Although graded banks are commonly used or planned in field applications, more work is needed to demonstrate their utility and to identify the most appropriate design procedure.

Novel Insights Into Mechanisms of Oil Recovery by Use of Low-Salinity-Water Injection

Abstract: The underlying mechanism of oil recovery by low salinity water injection (LSWI) is still unknown. It would, therefore, be difficult to predict the performance of reservoirs under LSWI. A number of mechanisms have been proposed in the literature but these are controversial and have largely ignored crucial fluid/fluid interactions. Our direct flow visualization investigations have revealed that a physical phenomenon takes place when certain crude oils are contacted by low salinity water leading to a spontaneous formation of micelles which can be seen in the form of micro-dispersions in the oil phase. In this paper, we present the results of a comprehensive study that includes experiments at different scales designed to systematically investigate the role of the observed crude oil/brine interaction and micelle formation in the process of oil recovery by LSWI. The experiments include; direct flow (micromodel) visualization, crude oil characterization, coreflooding, and spontaneous imbibition experiments. We establish a clear link between the formation of these micelles, the natural surface active components of crude oil, and the improvement in oil recovery due to LSWI. We present the results of a series of spontaneous and forced imbibition experiments carefully designed using reservoir cores to investigate the role of the micro-dispersions in wettability alteration and oil recovery. To further assess the significance of this mechanism, in a separate exercise, we eliminate the effect of clay by performing a LSWI experiment in a clay-free core. Absence of clay minerals is expected to significantly reduce the influence of the previously proposed mechanisms for oil recovery by LSWI. Nevertheless, we observe significant additional oil recovery compared to high salinity water injection in the clay-free porous medium. The additional oil recovery is attributed to the formation of micelles stemming from the crude oil/brine interaction mechanism described in this work and our previous related publications. Compositional analyses of the oil produced during this coreflood experiment indicates that the natural surface active compounds of the crude oil had been desorbed from the rock surfaces during the LSWI period of the experiment when the additional oil was produced. The results of this study present new insights into the fundamental mechanisms involved in oil recovery by LSWI and new criteria for evaluating the potential of LSWI for application in oil reservoirs. The fluid/fluid interactions revealed in this research applies to oil recovery from both sandstone and carbonate oil reservoirs.

Lost-Circulation Control for Formation-Damage Prevention in Naturally Fractured Reservoir: Mathematical Model and Experimental Study

Abstract: Drill-in fluid loss is the most important cause of formation damage during the drill-in process in fractured tight reservoirs. The addition of lost-circulation material (LCM) into drill-in fluid is the most popular technique for loss control. However, traditional LCM selection is mainly performed by use of the trial-and-error method because of the lack of mathematical models. The present work aims at filling this gap by developing a new mathematical model to characterize the performance of drill-in fluid-loss control by use of LCM during the drill-in process of fractured tight reservoirs. Plugging-zone strength and fracture-propagation pressure are the two main factors affecting drill-in fluid-loss control. The developed mathematical model consists of two submodels: the plugging-zone-strength model and the fracture-propagation-pressure model. Explicit formulae are obtained for LCM selection dependent on the proposed model to control drill-in fluid loss and prevent formation damage. Effects of LCMmechanical and geometrical properties on loss-control performance are analyzed for optimal fracture plugging and propagation control. Laboratory tests on loss-control effect by use of different types and concentrations of LCMs are performed. Different combinations of acid-soluble rigid particles, fibers, and elastic particles are tested to generate a synergy effect for drill-in fluidloss control. The derived model is validated by laboratory data and successfully applied to the field case study in Sichuan Basin, China.

What Factors Control Shale-Gas Production and Production-Decline Trend in Fractured Systems: A Comprehensive Analysis and Investigation

Abstract: A multi-physics model for shale gas production in fractured system, that couples real gas property, nano-flow mechanism and geomechanics