Computation of Gas-liquid Drainage In Fractured Porous Media Recognizing Fracture Liquid Flow

Abstract We propose a simple approach to simulate gas-oil gravity drainage process in fractured porous media by using an appropriate fracture capillary pressure curve and an expression for effective fracture liquid permeability. The effective fracture liquid permeability is approximated by fracture permeability perpendicular to fracture planes. There is no need to provide fracture relative permeabilities in our model Numerical simulation results are in excellent agreement with experimental data. Introduction Gravity drainage in fractured porous media is related to:matrix permeability. relative permeability and capillary pressure:matrix block height and fluid density; andfracture two phase gas-oil flow characteristics. Immiscible gas-oil flow in homogeneous matrix porous media is a resolved issue. Fracture two-phase gas-oil flow is, however, complicated. The fracture permeability from the Poiseuille law (k = 83.3 × 105 (2/)2, k in µm2 / in cm) is for flow parallel to fracture planes, and it may not apply lo flow perpendicular to fracture planes. Fracture relative permeability is also unknown. There is no reason to believe that a straight line relative permeability would apply to gas liquid flow across fractures. Limited measurements by McDonald et al and Pruess et al2reveal that fracture relative permeability may have a shape similar to matrix permeability. These measurement are, however for flow parallel to fracture planes. In a recent study(3). we have investigated liquid flow across a single liquid bridge between two matrix blocks. An expression for the effective liquid permeability perpendicular to the fracture planes was derived. As we will discuss later in this paper, the proposed expression may provide effective fracture liquid permeability for the gas-oil flow across a fracture. It could replace the need for both the Fracture absolute permeability and [he relative permeabilily in the direction perpendicular to fracture plane. In Reference (3), as well as in this study. one witnesses a substantial pressure drop across a liquid bridge (Figure I) in a fracture. Capillary pressure at the inflow end of a liquid bridge could be as much as 3 kPa lower than capillary pressure at the outflow end. In other words capillary pressure at the base of an upper matrix block could be 3 kPa lower than capillary pressure at the top face of the matrix block underneath. The large liquid pressure drop across a fracture provides the driving force for liquid flow from one matrix block to the nei1!hbouring block. Since the effect of gravity force across a fracture with an aperture of say 10 to 100 microns is negligible the flow across; both horizontal and vertical fractures requires the same pressure drop. In a recent study(4), we have noted that capillary continuity realizes across fractures as thick as 1.000 microns. The same study has also revealed that the Young-Laplace equation of capillarity may underestimate fracture capillary pressure. In another study(5), we demonstrated that a combination of fracture capillary pressure derived from the Young-Laplace equation and various expressions for fracture relative permeability may not fully describe gas-oil gravity drainage in Fractured porous media. </jats:sec

Perdido Development: Unified Fluid Model for Integrated-Production-System Modeling

Summary The Perdido development is one of the most-complex deepwater projects in the world. It is operated by Shell in partnership with Chevron and BP. It currently produces hydrocarbons from 12 subsea wells penetrating four separate reservoirs. The properties of produced fluid vary per reservoir as well as spatially. The producing wells display a relatively wide range of fluid gravities, between 17 and 41 °API, and producing gas/oil ratios (GORs), between 480 and 3,000 scf/bbl. The fluids produced from the subsea wells are blended in the subsea system and lifted to the topside facilities by means of five seabed caisson electrical submersible pumps. In the topside facility, gas and oil are separated, treated, and exported by means of dedicated subsea pipelines. The fluid compositions and properties across the various elements of the production system are used as input data to the respective simulation models, and the corresponding outcomes (e.g., fluid properties, compositions) vary upon the well/caisson lineup and daily operating conditions. Given the wide spectrum of fluids produced through the Perdido spar, a special equation-of-state (EOS) characterization of the fluids had to be developed. Because a common EOS model was used to characterize the fluids, we will call this the unified fluid model (UFM) throughout this study. This approach enables accurate and efficient prediction of the properties of blended fluids and is suitable for use in an integrated-production system model (IPSM) that connects reservoirs, wells, subsea-flowline networks, and topside-facilities models. Such a modeling scheme enables effective integration among relevant engineering disciplines and can represent production and fluid data from field history with high confidence. The IPSM uses a black-oil fluid description for the well and subsea-flowline network models. By use of the initial composition and producing GOR of each well, the fluid composition is estimated by means of a simple delumping scheme. The resulting composition is tracked through the subsea network to the topside-facilities model, where compositional flash calculations are performed. The IPSM can forecast production rates together with fluid properties and actual oil- and gas-volumetric rates across the whole production system. The model can be used to optimize production under constrained conditions, such as limited gas-compression capacity or plateau oil production.</jats:p

Viscous Displacement In Fractured Porous Media

Abstract In some fractured reservoirs, a gas pressure gradient of the order of 3–5 kPa/m may be established in the- fractures due to flow. Such a pressure gradient could result in recovery enhancement of the matrix oil. Several tests, are conducted to study viscous displacement in fractured porous media, with artificial fractures. These tests are analysed by using a fully-implicit finite difference simulator with appropriate fracture capillary pressure. The results show that there is considerable recovery improvement due to viscous displacement. For a gas pressure gradient of 3 kPa/m, the matrix oil recovery increases by 10% of PV in one of the tests. Introduction In fractured porous media comprised of matrix blocks and a fracture network, gravity and capillary forces affect the two-phase flow in the matrix blocks and the fractures. Capillary forces play a major role in the interaction between the matrix blocks via the capillary continuity mechanism(1). Gravity forces affect the drainage performance of the matrix blocks and the reinfiltration process (2). In addition to capillary and gravity forces, in certain cases, viscous forces are expected to affect the production performance of fractured reservoirs. Gas injection in some fractured reservoirs with low oil viscosity (say 0.2 mPa.s and an effective permeability to matrix permeability ratio of less than say 30) may result in a small pressure gradient in the fractures between an injection and production well. The gas pressure gradient in the fractures away from the well could be of the order of 3–5 kPa/m. Such a pressure gradient in the fractures improves matrix oil recovery by reducing the matrix capillary threshold height for gravity drainage and the capillary end effect in the horizontal displacement. There is no published data in the literature on viscous displacement in fractured porous media. The purpose of this work is to:provide experimental data on viscous displacement in fractured porous media for gas-oil displacement processes, andanalyse the data to examine the nature of displacement improvement from viscous forces. In the following, we first discuss the experimental set up and present the data, and then analyse the data using a finite difference simulator. FIGURE 1: Viscous displacement experimental setup.(Available in full paper) FIGURE 2: Matrix-fracture configurations used in the experiments (drawn not to scale). (Available in full paper) Experimental The apparatus schematic is depicted in Figure 1. It consists of a glass-walled case with metal top and bottom plates supported by metal framing. The metal framing allows the 0.95 cm thick glass plates to be forced against the rock faces. Design allows the setup to be tilted through 240 ° about a central horizontal axis. The glass case was sealed using fuel resistant room temperature vulcanizing fluorosilicone rubber. The bottom and the top end plates were made of 2.54 cm and 0.64 cm thick aluminum plates, respectively. Both plates provided connections for vacuum, ventilation, gas injection, fluid loading and drainage (see Figure 1). A valve mounted 6 cm above the bottom face of the coreholder allows gas to flow out freely without interfering with liquid flow. </jats:sec

Numerical Investigation of Gravitational Compositional Grading in Hydrocarbon Reservoirs Using Centrifuge Data

Summary Fluid properties descriptions are required for the design and implementation of petroleum production processes. Increasing numbers of deep water and subsea production systems and high-temperature/high-pressure (HTHP) reservoir fluids have elevated the importance of fluid properties in which well-count and initial rate estimates are quite crucial for development decisions. Similar to rock properties, fluid properties can vary significantly both aerially and vertically even within well-connected reservoirs. In this paper, we have studied the effects of gravitational fluid segregation using experimental data available for five live-oil and condensate systems (at pressures between 6,000 and 9,000 psi and temperatures from 68 to 200°F) considering the impact of fluid composition and phase behavior. Under isothermal conditions and in the absence of recharge, gravitational segregation will dominate. However, gravitational effects are not always significant for practical purposes. Since the predictive modeling of gravitational grading is sensitive to characterization methodology (i.e., how component properties are assigned and adjusted to match the available data and component grouping) for some reservoir-fluid systems, experimental data from a specially designed centrifuge system and analysis of such data are essential for calibration and quantification of these forces. Generally, we expect a higher degree of gravitational grading for volatile and/or near-saturated reservoir-fluid systems. Numerical studies were performed using a calibrated equation-of-state (EOS) description on the basis of fluid samples taken at selected points from each reservoir. Comparisons of measured data and calibrated model show that the EOS model qualitatively and, in many cases, quantitatively described the observed equilibrium fluid grading behavior of the fluids tested. First, equipment was calibrated using synthetic fluid systems as shown in Ratulowski et al. (2003). Then real reservoir fluids were used ranging from black oils to condensates [properties ranging from 27° API and 1,000 scf/stb gas/oil ratio (GOR) to 57°API and 27,000 scf/stb GOR]. Diagnostic plots on the basis of bulk fluid properties for reservoir fluid equilibrium grading tendencies have been constructed on the basis of interpreted results, and sensitivities to model parameters estimated. The use of centrifuge data was investigated as an additional fluid characterization tool (in addition to composition and bulk phase behavior properties) to construct more realistic reservoir fluid models for graded reservoirs (or reservoirs with high grading potential) have also been investigated.</jats:p

Analytical Theory of Combined Condensing/Vaporizing Gas Drives

SUMMARY Analytical solutions are presented that confirm the existence of a combined condensing and vaporizing displacement mechanism in enriched gas drives. The solutions are derived for dispersion-free, one-dimensional displacements in four-component hydrocarbon systems. A simple geometric construction is used to find a key tie line in the solution, the "crossover" tie line. This tie line is shown to control the development of miscibility in condensing/vaporizing systems, and it connects the condensing and vaporizing portions of the displacement.</jats:p

A New and Practical Oil-Characterization Method for Thermal Projects: Application to Belridge Diatomite Steamflood

Summary Most of the oil-characterization approaches for thermal recovery are designed for heavy oils at moderate temperatures, in which oil can be represented in very simplistic ways (such as “gas” and “oil”). However, when oil is exposed to very high steam temperatures (i.e., 550°F), and/or the oil is lighter than the classical range defined for heavy oils and is exposed to a wide spectrum of thermal effects, such as distillation of the lighter ends, the conventional methods of representing the interaction of steam and the in-situ fluids are not accurate. In many cases, we have to first evaluate the quality of the data, and then represent the average behavior with a single most likely fluid model per reservoir segment (plus other scenarios, as needed) to simulate the production performance. There is a need to develop a streamlined approach to bring such data into industrial simulators in a practical way. In this study, we have developed a fit-for-purpose approach to generate a consistent pressure/volume/temperature (PVT) model over the whole reservoir, reflecting both pressure and temperature changes through the entire oil accumulation. The model represents the oil viscosity for a wide spectrum of temperatures, from reservoir temperature to steam temperature (thermal-process range). A systematic lumping scheme enables conversion of the characterized PVT model for numerical simulators with the minimal number of pseudocomponents while still capturing the essence of thermal physics. To our knowledge, there is no systematic study of this nature available in the literature. We have tested this approach in the Belridge diatomite steamdrive project. The study confirmed that steamflood incremental oil production in a light-oil reservoir is sensitive to the component-lumping scheme because of distillation of the lighter ends. We also found that a five-component PVT model, representing the physics in “fit-for-purpose” dynamic simulation, best compromises between minimal number of components and physical description of the light-oil behavior.</jats:p