Mark H. Holtz

Residual Gas Saturation to Aquifer Influx: A Calculation Method for 3-D Computer Reservoir Model Construction

Residual gas saturation controls the volume of gas trapped in that portion of the reservoir that has experienced water encroachment. As water moves into a rock volume filled with gas, the water displacement of the gas is incomplete. The water fills pores and pore throats, causing capillary pressure and relative permeability effects to stop the flow of gas and allow only water to pass through the rock volume. This stoppage results in gas being trapped behind the encroaching waterfront as residual gas. The volume and location of the residual gas are controlled by the distribution of the petrophysical properties. A method based on interrelationships between petrophysical properties is used to create a model for calculating maximum residual gas saturation (Sgrm). The model is developed as a function of porosity, permeability, capillary pressure, and initial water saturation. The input to the model and its results compare favorably with actual field data where aquifer encroachment is verified from well production history.

Testing efficiency of storage in the subsurface: frio brine pilot experiment

Can we demonstrate that subsurface storage is an effective method of reducing emissions of CO2 to the atmosphere? The Frio Brine Pilot Experiment is designed to test storage performance of a typical subsurface environment in an area where large-volume sources and sinks are abundant, near Houston, Texas, USA. We employed extensive pre-experiment characterization and modeling to identify significant factors that increase or decrease risk of leakage from the injection zone. We then designed the experiment to focus on those factors, as well as to test for presence or absence of events that are not expected. A fully developed reservoir model of heterogeneous reworked fluvial sandstones of the Frio Formation documents three-dimensional compartmentalization of the injection horizon by faulting associated with salt-dome intrusion and growth. Modeling using the TOUGH2 simulator showed that a significant source of uncertainty for subsurface performance of injected CO2 is residual CO2 saturation during storage. If initial displacement of water during injection is efficient and capillary effects create the expected residual saturation of 30 percent CO2, the volume occupied by the plume will be limited, and long-term storage can be expected even in an open system. If, however, during injection, CO2 moves out from the injection well along high-permeability pathways, it may not contact most pores, and residual saturation will have a smaller effect on storage. Our experiment is therefore designed to monitor plume geometry and CO2 saturation near the injection well and closely spaced observation well. Leakage out of the injection zone as a result of well engineering or other flaws in the seal is also monitored in the sandstone immediately overlying the injection zone and at the surface using multiple techniques. Permitting strategies include cooperation among two State agencies, as well as Federal NEPA assessment, because of the innovative aspects of the experiment.

Geologic framework of upper Miocene and Pliocene gas plays of the Macuspana Basin, southeastern Mexico

This integrated study provides a geological and geochemical framework for upper Miocene and Pliocene siliciclastic gas plays in the Macuspana Basin. Structural controls for the plays are deep-seated faults that tap Mesozoic thermogenic gas sources, areas of intense shale diapirism and folding, and areas with structural inversion that could enhance trapping and reservoir productivity. Early Neogene thrusting south of the basin triggered evacuation of Oligocene shale along northwest-dipping listric faults in the eastern and southeastern basin margin. These faults are associated with large-scale rollover structures and thick (500 m) upper Miocene shoreface and wave-dominated deltaic complexes. A second phase of extension in the early Pliocene formed a set of broad, southeast-dipping listric faults in the western basin, controlling thick accumulations of stacked Pliocene shoreface deposits. Trap formation and enhancement in the southern basin margin are linked to late Miocene to Pliocene inversion.The primary stratigraphic controls on play occurrence in the upper Miocene in the onshore part of the basin are the regional facies distribution of northwest-prograding shoreface and wave-dominated deltaic systems. There was a shift in Pliocene sedimentation from the southeast to the west and northwest parts of the basin, where thick successions of aggradational shoreface and wave-dominated deltaic deposits accumulated in depocenters defined by shale evacuation along growth faults. Valley-fill deposits in both the upper Miocene and Pliocene resulted from shortlived periods of base-level change induced by either uplift on the southern basin margin or eustasy. The offshore part of the basin is inferred to consist of deep-water turbidite deposits that formed downdip (westward) of a hypothesized mixed clastic-carbonate prograding complex from the Yucatan platform.Three petroleum systems (Mesozoic, Paleogene–lower Neogene, and upper Miocene–Pliocene) contributed to the hydrocarbon accumulations and hydrocarbon generation and migration in the basin. Principal Upper Jurassic/Lower Cretaceous source rocks generated wet thermogenic gases and oil. Secondary lower Tertiary source rocks generated dominantly dry biogenic gases. Mixtures of the two gas types are common. Numerous deep-seated growth faults and faults serve as pathways for Mesozoic-sourced hydrocarbons. Surface seeps and abundant gas shows suggest that hydrocarbons are being generated today.

Identifying Fracture Orientation in a Mature Carbonate Platform Reservoir

The Permian (Guadalupian) San Andres reservoir at Keystone field, Winkler County, Texas, is divided into three major stratigraphic units and twelve flow units on the basis of an analysis of multiple shoaling-upward cycles of shallow-water marine to tidal-flat carbonate facies. These rocks are now thoroughly dolomitized and cemented with anhydrite and gypsum. The distribution of original oil in place was mapped both laterally and vertically. Most of the resource is in the upper five flow units, and the original-oil-in-place map of these upper flow units indicates that the highest concentration of hydrocarbons is in the center of the study area. Porosities in this reservoir are nearly 10%, and permeabilities are generally less than 1 md. Despite these low matrix permeabilities, recently drilled wells initially produced at rates as high as 120 bbl of oil per day, although these rates declined an average of 75% in the first 6 months. Primary recovery from this reservoir is only 8% of original oil in place. Subvertical fractures in this reservoir are visible in cores and on a microimage log. Early floodwater breakthrough occurred without increased oil production in a pilot waterflood. These production characteristics, combined with direct observations of fractures, indicate that productivity is dependent on fracture permeability. Horizontal boreholes perpendicular to the strike of effective fractures and within the part of the reservoir that contains highest remaining oil will maximize primary recovery. Borehole breakouts and regional stress measurements suggest that the direction of principal horizontal compressive stress is northeast-southwest, and natural fractures that strike in this direction are most likely to be open and capable of transmitting fluids.

Approaches to Identifying Reservoir Heterogeneity and Reserve Growth Opportunities in a Continental-Scale Bed-Load Fluvial System: Hutton Sandstone, Jackson Field, Australia

We applied an integrated geologic and engineering approach devised to identify heterogeneities in the subsurface that might lead to reserve growth opportunities in our analysis of the Hutton Sandstone at Jackson field, Eromanga basin, Australia. Our approach involves four key steps: (1) determine geologic reservoir architecture, (2) investigate trends in reservoir fluid flow, (3) integrate fluid-flow trends with reservoir architecture, and (4) estimate original oil in place, residual oil saturation, and remaining mobile oil to identify opportunities for reserve growth. Although the Hutton reservoir is interpreted as the deposit of a continental-scale bed-load fluvial system and is dominated by highly permeable sandstone, the genetic stratigraphic analysis identified numerous thin, but widespread, shale units deposited during lacustrine flooding that periodically interrupted episodes of coarse clastic Hutton deposition. These shales represent chronostratigraphically significant surfaces, but more importantly, the trends in reservoir fluid flow, established from monitoring aquifer encroachment, production response to water shut-off workovers, and differential depletion in repeat formation tests, indicate that these shale units act as efficient barriers to vertical fluid flow. Erosion of the upper part of the Hutton reservoir by the younger Birkhead mixed-load fluvial system caused further stratigraphic complexities, introducing additional barriers to vertical and lateral migration of mobile oil and aquifer encroachment. These stratigraphic complexities were not fully appreciated in previous field development and production strategies, and the potential exists for incremental reserve growth through geologically targeted infill drilling and recompletions.

GEO-SEQ Best Practices Manual. Geologic Carbon Dioxide Sequestration: Site Evaluation to Implementation

LBNL-56623 GEO-SEQ Best Practices Manual Geologic Carbon Dioxide Sequestration: Site Evaluation to Implementation GEO-SEQ Project Team Lawrence Berkeley National Laboratory, Lawrence Livermore National Laboratory, Oak Ridge National Laboratory, Stanford University, University of Texas Bureau of Economic Geology, Alberta Research Council September 30, 2004 Earth Sciences Division Ernest Orlando Lawrence Berkeley National Laboratory Berkeley, CA 94720 This work was supported by the Assistant Secretary for Fossil Energy, Office of Coal and Power Systems, of the U.S. Department of Energy (DOE) under Contract No. DE-AC03-76SF00098.

Petrophysical Characterization of Permian Shallow-Water Dolostone

The complex interplay between depositional facies and diagenesis in dolostones presents numerous challenges for calculating petrophysical properties from wireline logs. Complex pore geometries and mineralogies control rock petrophysical properties, and equations for calculating porosities and saturations must therefore be tailored to specific pore geometry-mineralogy combinations. The complex mineralogy of some dolostone reservoirs, moreover, has profound effects on wireline log measurements. If dolostone reservoirs are divided into petrophysical-mineralogical facies of similar depositional and diagenetic textures and, thus, similar pore geometries and mineralogy, empirical equations that apply specifically to that geologically identified petrophysical-mineralogical facies can be developed so that porosity and water saturation can be calculated accurately. We present some examples from Permian shallow-water dolostone reservoirs of the Permian Basin, southwestern United States, that demonstrate analytical approaches for calculating petrophysical properties in these complex rock types. The four general petrophysical-mineralogical facies that characterize Permian shallow-water dolostone reservoirs are (1) subtidal, muddominated dolostone; (2) subtidal, grain-dominated dolostone; (3) dolomitic and siliciclastic peritidal rocks; and (4) diagenetically altered, subtidal dolostone.

Integrated geologic and engineering determination of oil-reserve-growth potential in carbonate reservoirs

Leonardian restricted-platform carbonate reservoirs in the Permian Basin in West Texas and southeastern New Mexico exhibit abnormally low recovery efficiencies. Cumulative production form these mature reservoirs is only 18% of the original oil in place (OOIP), or about one-half the average recovery efficiency of Permian Basin carbonate reservoirs. Low recovery efficiency is directly related to high degrees of vertical and lateral facies heterogeneity caused by high-frequency, cyclic sedimentation in low-energy, carbonate platform environments and by equally complex postdepositional diagenesis. This paper reports that because of their geologic complexity, these reservoirs have high reserve-growth potential.

Assessing impacts to groundwater from CO2-flooding of SACROC and Claytonville oil fields in West Texas

Comparison of groundwater above two Permian Basin oil fields (SACROC Unit and Claytonville Field) near Snyder, Texas should allow us to assess potential impacts of 30 years of CO2-injection. CO2-flooding for enhanced oil recovery (EOR) has been active at SACROC in Scurry County since 1972. Approximately 13.5 million tons per year (MtCO2/yr) are injected with withdrawal/recycling amounting to ~7MtCO2/yr. It is estimated that the site has accumulated more than 55MtCO2; however, no rigorous investigation of overlying groundwater has demonstrated that CO2 is trapped in the subsurface. Mineralogy of reservoir rocks at the Claytonville field in southwestern Fisher County is similar to SACROC. CO2-EOR is scheduled to begin at Claytonville Field in Fisher County in early 2007. Here we have the opportunity to characterize groundwater prior to CO2-injection and establish baseline conditions at Claytonville. Methods of this study will include: (1) examination of existing analyses of saline to fresh water samples collected within an eight-county area encompassing SACROC and Claytonville, (2) additional groundwater sampling for analysis of general chemistry plus field-measured pH, alkalinity, and temperature, stable isotopic ratios of hydrogen (D/H), oxygen (O/O), and carbon (C/C), and (3) geochemical equilibrium and flowpath modeling. Existing groundwater data are available from previous BEG studies, Texas Water Development Board, Kinder Morgan CO2 Company, and the U. S. Geological Survey. By examining these data we will identify regional groundwater variability and focus additional sampling efforts. The objective of this study is to look for potential impacts to shallow groundwater from deep CO2-injection. In the absence of conduit flow from depth, we don’t expect to see impacts to shallow groundwater, but methodology to demonstrate this to regulators needs to be established. This work is a subset of the Southwest Regional Partnership on Carbon Sequestration Phase 2studies funded by the Department of Energy (DOE) in cooperation with industry and government partners. Biographical Sketches Rebecca C. Smyth holds an M. A. in geology (specialty in hydrogeology) from University of Texas at Austin and is a registered professional geologist in the State of Texas. Over the past 10 years at BEG her work has included groundwater impact studies related to oil and gas exploration and production throughout Texas and elevated levels of arsenic in south Texas. Mark H. Holtz has more than 20 years of reservoir characterization experience at the BEG. He has focused on integration of geology and engineering in both carbonate and siliciclastic oil and gas reservoirs throughout the U.S. Gulf Coast, the Australian Cooper and Eromanga Basins, the Vienna Basin, Venezuela, Argentina, and Mexico. Stephen N. Guillot is Senior Reservoir Engineer for Kinder Morgan CO2 Co. LP. He is managing Kinder Morgan’s industry support of Southwest Regional Partnership for Carbon Sequestration research studies at the SACROC Unit and Claytonville Field east of Snyder, Texas. BEG SWCARB Project Assessing Impacts to Groundwater from CO2-flooding of SACROC and Claytonville Oil Fields in West Texas Rebecca C. Smyth, Mark H. Holtz, and Stephen N. Guillot with acknowledgments to: Jean-Philippe Nicot, Susan D. Hovorka, and others Bureau of Economic Geology Jackson School of Geosciences The University of Texas at Austin and Kinder Morgan CO2 Company L.P., Houston, Texas BEG SWCARB Project Overview of Hydrogeologic Study • Eight county study area encompasses SACROC (Scurry Area Canyon Reef Operations Committee) Unit and Claytonville fields in west Texas, • Physical and chemical data sources on groundwater (fresh to saline) include: previous BEG studies, Texas Water Development Board (TWDB), Kinder Morgan CO2, and U. S. Geological Survey, • Identify regional variability in physical and hydrogeochemical properties of groundwater from existing analyses, • Conduct additional sampling for major ion, total organic carbon, stable isotopes of hydrogen (D/H), oxygen (18O/16O), and carbon (13C/12C); pH, temperature, and alkalinity field measurements, might install two new water wells in Claytonville, • Look for geochemical evidence of mixing starting with simple approach: decreased pH, decreased temperature, ion plots, • Geochemical equilibrium and flowpath modeling to identify groundwater mixing. Models being considered include: PHREEQC, SOLMNEQ.88, EQ3/EQ6, Geochemist’s Workbench. BEG SWCARB Project Background • SMALL subset of Southwest Regional Partnership on Carbon Sequestration Phase 2 studies funded by Department of Energy (DOE) in cooperation with industry (Kinder Morgan CO2) and government (New Mexico Tech, and LANL) partners. BEG water portion is a four-year project (50% time years 1&2, 25% time years 3&4). • Since 1972, ~13.5 million tons per year (MtCO2/yr) injected at SACROC with withdrawal and recycling amounting to ~7MtCO2/yr. Estimated that site has accumulated more than 55MtCO2. • CO2 sources in southwestern Colorado and northern New Mexico for which there are stable isotopic data available in literature. BEG SWCARB Project Kinder Morgan CO2 Assets

Reactivation of mature oil fields through advanced reservoir characterization: A case history of the Budare field, Venezuela

Budare field has produced 95 million bbl of oil since discovery in 1954, but a sustained 6 yr decline during the early 1990s reduced daily production to 3000 bbl of oil. Reactivation of the field as a result of this reservoir characterization study increased production by 13,000-16,000 BOPD, a rate that has been maintained in the 4 yr since the study was completed, resulting in an incremental recovery of more than 24 million bbl of oil. This increase in production was achieved through integrated reservoir characterization that identified the depositional heterogeneities and structural complexities responsible for intrareservoir entrapment of the bypassed oil in the field. The main producing zones are the Tertiary-age Merecure and Oficina reservoirs that are interpreted as the deposits of large-scale bed-load and mixed-load fluvial and wave-dominated deltaic depositional systems. The geologic analysis indicates that the large-scale systems are divided internally, or vertically stratified, by thin but widespread shale markers resulting from flooding episodes and that facies variability introduces lateral discontinuities. Syn- and postdepositional faulting further disrupts reservoir continuity. Trends in fluid flow established from engineering analysis of initial fluid levels, response to recompletion workovers, and pressure depletion data demonstrated that these geologic heterogeneities (flooding shale markers, lateral facies pinch-out, and faults) are effective barriers to lateral and vertical fluid flow. Considerable potential for sustained production exists at Budare field because the reservoir units are highly compartmentalized. Identification and targeting of the poorly drained and uncontacted compartments at Budare facilitated the development of a production optimization portfolio that encompassed four principal advanced-recovery opportunities: field extension or step-out; attic areas of the reservoir that are structurally higher than existing production and, hence, poorly drained; stratigraphically and structurally defined compartments that have not been tapped; and compartments that are poorly drained. Successful geologically targeted infill wells and strategic recompletions in these bypassed compartments achieved a sustained fivefold increase in daily production in the mature Budare field.