Shallow Shelf Carbonate Reservoir Research Articles

EOR Field Experiences in Carbonate Reservoirs in the United States

Summary A considerable portion of the world's hydrocarbon endowment is in carbonate reservoirs. Carbonate reservoirs usually exhibit low porosity and may be fractured. These two characteristics along with oil-to-mixed wet rock properties usually result in lowered hydrocarbon recovery rates. When enhanced oil recovery (EOR) strategies are pursued, the injected fluids will likely flow through the fracture network and bypass the oil in the rock matrix. The high permeability in the fracture network and the low equivalent porous volume result in early breakthrough of the injected fluids. Infill drilling programs and well conformance strategies—mostly gas and water shutoff—have been effectively used to mitigate the early breakthrough and increase oil recovery. In most cases, however, 40 to 50% of the original oil in place (OOIP) is not produced. A large number of EOR field projects in carbonate reservoirs have been referenced in the literature since the early 1970s. These field projects demonstrate the technical feasibility of various EOR methods in carbonate reservoirs. However, because of the collapse in oil prices, most of the aforementioned project plans have been abandoned. This paper presents a comprehensive compilation of EOR (Gas, Chemical, and Thermal methods) field experiences in carbonate reservoirs within the US, as an attempt to identify key variables and project design parameters for future evaluation and revitalization of mature carbonate reservoirs. Carbon dioxide flooding [continuous or water-alternating gas (WAG)] is the dominant EOR process used in the US This is because of the high availability of low-cost CO2. CO2 EOR in particular represents the logical first step towards viable geologic carbon storage and sequestration. EOR chemical methods in carbonate reservoirs, especially polymer flooding, have been widely tested in US carbonate reservoirs. However, EOR chemical methods have made a marginal contribution, relatively, in terms of total oil recovered. Our study includes a brief overview of current laboratory (e.g. wettability changes and novel chemical additives) and field (e.g. injectivity enhancement) experiences in EOR chemical methods in carbonate formations. A brief discussion surrounding the screening methods used to identify viable EOR opportunities in carbonate fields based on past and present experiences is also included. Introduction Carbonate reservoirs are naturally-fractured geologic formations characterized by heterogeneous porosity and permeability distributions. In the case of low porosity and low permeability carbonate rocks (more specifically rock matrices), the fluid flow in the reservoir can be completely dependent on the fracture network while the matrix only plays a source role (analogous to tight sand formations and natural gas flow). In the case of porous carbonate rocks, fracture networks can cause uneven sweeping of the reservoir, leading to early breakthrough of injected fluids in the producing wells and resulting in low recovery factors. The abundance of carbonate reservoirs has been the subject of numerous studies attempting to characterize their heterogeneities, classify different types of fractured reservoirs, and determine how rock and fluid properties have an impact on ultimate recovery (Roehl et al. 1985; Allan and Qing Sun 2003; Carr et al. 2001; Grave et al. 2000; Benson et al. 1998; Wardlaw 1996). The TORIS database (maintained by the US Department of Energy) indicates 22% of the OOIP in the US is contained in shallow-shelf carbonate reservoirs. Currently in the US, these types of reservoirs exist in more than 14 states with over 70% of the OOIP located in reservoirs in Texas and New Mexico, mostly concentrated in the Permian Basin (Nuckols 1992, Xie et al. 2005). Over the last three decades, primary production, waterflooding, and CO2 floods, combined with infill drilling programs, have been the most widely used recovery methods. However, other EOR strategies have been tested in the past and there are currently several active research programs seeking alternatives to increase the recovery factor of these mostly light crude-oil reservoirs economically. Although the Permian Basin (west Texas and southeast New Mexico) can be considered mature, its potential for improved oil recovery is still very high. A recent study reports that there is an estimated 30 billion barrels of mobile oil in the Permian Basin, reiterating the strategic importance of EOR technologies for carbonate reservoirs and their impact on US oil production (Nuckols 1992; Xie et al. 2005; Seethepalli et al. 2004; Moritis 2004; Cole 2003; Moritis 2003; Dutton et al. 2004).

Improved Oil Recovery From Carbonate Reservoirs by Chemical Stimulation

Summary Oil reserves from shallow-shelf carbonate reservoirs account for 22% of the original oil in place (OOIP) of the entire U.S. oil resource. Many of these reservoirs are naturally fractured. A pressure-pulsing technique has been used in fractured fields to improve oil recovery. In some situations, imbibition of water can be promoted by chemical stimulation to alter the reservoir wettability toward water-wetness such that oil is expelled at an economic rate from the rock matrix into fractures. Shallow-shelf (i.e., Class II) carbonate reservoirs typically produce less than 10% OOIP during primary recovery and respond poorly to water injection. In this work, promotion of imbibition was determined for a cationic surfactant, cocoalkyltrimethyl ammonium chloride (CAC), and a nonionic surfactant, an ethoxylated alcohol (POA). Cores from three dolomitic Class II reservoirs, Cottonwood Creek, Dagger Draw, and Lustre, were used in the laboratory tests. After preparing core samples using the corresponding reservoir crude oil and brine, spontaneous expulsion of oil was measured in glass imbibition cells at elevated temperature for more than 50 core samples. When reservoir brine was used as the imbibition fluid, oil recovery was in the range of 0 to 35% OOIP. After imbibition of reservoir brine had ceased, the cores were transferred into surfactant solutions at or somewhat above the critical micelle concentration (CMC) to test for enhanced recovery by further imbibition. Typically, immersion in the surfactant solution resulted in an additional recovery of 5 to 10% OOIP. The increased recovery is mainly ascribed to increased water–wetness. The effect of acidization before surfactant treatment was also tested and found to be detrimental to oil recovery.

Chemical Stimulation Improves Oil Recovery From Carbonate Reservoirs

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89424, "Improved Oil Recovery From Carbonate Reservoirs by Chemical Stimulation," by X. Xie, SPE, and W.W. Weiss, SPE, Correlations Co., and Z. Tong, SPE, and N.R. Morrow, SPE, U. of Wyoming, prepared for the 2004 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 17-21 April. Often, a pressure-pulsing technique is used in naturally fractured shallow-shelf carbonate reservoirs to improve oil recovery. However, in some situations, imbibition of water can be promoted by chemical stimulation to alter the reservoir wettability toward water-wetness such that oil is expelled at an economic rate from the rock matrix into fractures. In this work, promotion of imbibition was deter-mined for a cationic surfactant and a nonionic surfactant. Introduction Approximately 22% of the original oil in place (OOIP) in the U.S. was in shallow-shelf carbonate reservoirs. Most of these reservoirs are heterogeneous and naturally fractured, and waterflooding leads to bypassed rock matrix and early water breakthrough. Spontaneous imbibition can aid oil recovery from fractured reservoirs. However, spontaneous imbibition occurs only when the pore surfaces are effectively water-wet, such that water imbibes into the rock matrix, expelling oil into the fractures and flushing it toward the production wellbore. The significance of spontaneous imbibition as a recovery mechanism was recognized for the naturally fractured water-wet Spraberry field in west Texas in the 1950s, and this method is still being pursued. Oil recovery by spontaneous imbibition into fractured chalk is a key production mechanism for North Sea chalk reservoirs. Also, it has been reported that pressure pulsing, intended to stimulate imbibition, increased the oil-producing rate and ultimate recovery from individual wells in Wyoming. Laboratory studies provided direct demonstration of spontaneous imbibition as a recovery mechanism. If rocks are oil-wet or neutral-wet, imbibition does not occur. Use of surfactants to alter the rock’s surface toward water-wetness to promote imbibition of water into the matrix of fractured reservoirs has been recognized as an important mechanism for enhanced recovery. Applying petroleum sulfonates for tertiary recovery from sandstone reservoirs has been under investigation for more than 50 years. Use of these comparatively low-cost surfactants in carbonate reservoirs is problematic because of adsorption resulting from the positive charge of the rock surface. The use of anionic surfactant in combination with sodium carbonate has been proposed. At high pH, the carbonate ion is the potential-determining ion and reverses the charge of the carbonate surface to mitigate the adsorption problem. The full-length paper details laboratory imbibition tests on combinations of crude oil, water, and rock for three carbonate (dolomite) reservoirs. All three reservoirs have a long history of very low oil recovery. Performance often is ascribed to the combined effect of fractures and the unfavorable wetting state of the rock matrix with respect to spontaneous imbibition. The objective of this work was to assess the potential for single-well surfactant stimulation by injecting low-concentration surfactant solutions. The main focus was to study the effectiveness of nonionic and cationic surfactants.

Abstract: Diagenetic Characterization of Shallow-Shelf Carbonate Reservoirs, Pennsylvanian Paradox Formation, Southern Paradox Basin, Utah 

Abstract: Diagenetic Characterization of Shallow-Shelf Carbonate Reservoirs, Pennsylvanian Paradox Formation, Southern Paradox Basin, Utah 

Abstract: Seismic Guided Mapping of Effective Porosity, Grayburg/San Andres Shallow Shelf Carbonate Reservoir, Permian Basin, USA

Abstract: Seismic Guided Mapping of Effective Porosity, Grayburg/San Andres Shallow Shelf Carbonate Reservoir, Permian Basin, USA

Abstract: Improved Modeling of a Shallow Shelf Carbonate Reservoir using 3-D Seismic Attributes, Welch Field, Permian Basin, Texas

Abstract: Improved Modeling of a Shallow Shelf Carbonate Reservoir using 3-D Seismic Attributes, Welch Field, Permian Basin, Texas

From the Pore Scale to Reservoir Scale: Lithohydraulic Flow Unit Characterization of a Shallow Shelf Carbonate Reservoir, North Robertson Unit, West Texas: ABSTRACT

This paper presents the results of integrated geological-petrophysical reservoir characterization performed as part of the US Department of Energy Class II reservoir program. Petrographic image analysis, using a specially equipped SEM, allowed for the identification of 8 petrophysical rock types at the North Robertson Unit. Detailed log analysis resulted in the development of algorithms for the log-based identification of these rock types in 109 wells. Porosity was related to permeability for each Rock Type: thus permeability is determined from well log data. Evaluation of porosity, permeability, Sw and HPV distribution has allowed for the identification of 12 lithohydraulic flow units. These flow units have been mapped across the unit. The technique allows for the development of log-based reservoir models that are simulator-ready. The results of this study have application to all heterogeneous, shallow shelf carbonate reservoirs, they demonstrate that large fields can be successfully characterized using few cores and emphasize the importance of integrated geological-engineering analysis in reservoir characterization.

Seismic Estimation of Porosity in the Permian San Andres Carbonate Reservoir, Welch Field, Dawson, County, Texas: ABSTRACT

OXY and the DOE Are partners in a advanced technology demonstration project at OXY`s West Welch Unit. Production is from a low permeability San Andres reservoir of Permian age similar to many shallow shelf carbonate reservoirs in the Permian Basin. The project involves the construction of a detailed geological model for numerical simulation to design and then conduct a CO{sub 2} flood of the reservoir. Depositional textures of the reservoir rock are highly variable from diagenesis, mostly anhydritic cementing, creating a highly complex pore system. Identification of the interwell reservoir continuity and flow units present the greatest challenge to the reservoir description. A 1993 vintage 3-D seismic survey with a bin spacing of 110{prime} by 165{prime} has been used to assist with the interwell reservoir description. The structure definition at the top and base of the reservoir have been accurately mapped with respect to the well data. Core and well log measurements of porosity, permeability and water saturation were computed and summed across the seismic reservoir interval. Measurements of amplitude, frequency and phase within the 3-D volume were summed across the reservoir interval. All seismic attributes were sampled to the wells and compared through scatterplots to the well log andmore » core measurements. Excellent correlation between three seismic attributes and porosity has been documented. A deterministic method has been used to estimate porosity values at each seismic bin location. The method uses the seismic measurements to shape the geology between the wells while maintaining agreement with the well data at the well locations.« less

Reservoir Characterization, Modeling, and Simulation in the Welch San Andres Field: ABSTRACT

As a part of a DOE funded Class II project aimed at improving oil recovery in shallow shelf carbonate reservoirs, detailed characterization, modeling and reservoir simulation is ongoing in Oxy USA`s West Welch Unit in the Welch, San Andres field. The initial effort at modeling the reservoir, which is described in this report, is based on all the available core and log data in the study area. A final report will compare these results to reservoir modeling enhanced by high resolution seismic data obtained from cross wellbore tomography. The reservoir model was built using the following methodology: (1) Determine sequence stratigraphic framework from core data. (2) Identify rock fabrics from thin sections. (3) Quantify porosity versus permeability relationship for each rock fabric. (4) Identify rock fabrics from log data. (5) Use unique porosity versus permeability relationship for each rock fabric to transform log porosity to permeability. (6) Define reservoir model flow units using sequence stratigraphic framework and identified rock fabrics. Each layer (flow unit) is then mapped, gridded and exported to the simulator. The simulation can then be compared to actual production history. Using this methodology a good history match was easily obtained from the simulation with very little modificationmore » of the simulation parameters in two different Welch field model areas. These results give great confidence in the subsequent simulation of reservoir response to CO{sub 2} flooding.« less

Flow Unit Modeling of a Heterogeneous Shallow Shelf Carbonate Reservoir (Clear Fork/Glorieta), North Robertson Unit, Gaines County, Texas: ABSTRACT

Flow Unit Modeling of a Heterogeneous Shallow Shelf Carbonate Reservoir (Clear Fork/Glorieta), North Robertson Unit, Gaines County, Texas: ABSTRACT