Abstract

The 2.8 Billion Barrel (Original Oil in Place) SACROC Unit is located in Scurry County, Texas and produces from the Pennsylvanian-aged Cisco and Canyon Formations of the Kelly-Snyder and Diamond M Fields. Structurally, these fields are developed on the Horseshoe Atoll in the Midland Basin of West Texas. As is the case with many such Pennsylvanian reef complexes, the SACROC Unit exhibits a great deal of vertical relief and laterally complicated geometries.

This highly heterogeneous reservoir is currently the focus of tertiary (CO₂) recovery efforts. Due to the sensitive nature of mechanical, physical, and economic constraints on tertiary recovery operations, it is important to have a good understanding of the reservoir and fluid migration within it. In order to develop that understanding, Kinder Morgan recently acquired a 4-D (Time Lapse) cross-well seismic data set in the active project area using Core Labs / Tomoseis (now Z-Seis) equipment and processing. Four baseline surveys (surveys done prior to CO₂ injection start-up) were shot from a central well. Each survey was about 2000’ long, and was arranged so that the source and receiver tools were in producers, with an injector approximately half way across the section. Two of the profiles were along strike in a local build-up, one traversed the crest of local structure, and the fourth covered the steeply dipping mound edge. The baseline surveys provided assistance for reservoir characterization efforts by providing vertical resolution on a 10-15 foot scale, and clearly display multiple depositional events in the dip section. Additionally, repeat surveys (surveys taken after CO₂ injection) allow for the tracking of CO₂ in the reservoir. This is accomplished by comparing the seismic velocity profiles between the wells (both laterally and vertically) after the less dense CO₂ phase has replaced original fluids (oil and water).

Abstract

The Pleistocene Wisconsin Glaciation is considered by many geoscientists to have been a major glaciation event. It has been documented to have caused mean sea level to be lowered by 135 meters below the present-day mean sea level. If 135 meters is assumed to be a major sea level fluctuation caused by the process of glaciation, then a mean sea level fluctuation significantly greater than 135 meters should require consideration of a process other than glaciation to achieve the effect of such a large fluctuation.

The Permian Delaware Mountain Group is currently considered by most geoscientists to have been deposited in water depths greater than 135 meters by non-Newtonian flow processes including turbidity and density currents.

If the Delaware Mountain Group was deposited by Newtonian flow processes, including lacustrine, fluvial, tidal and shallow water marine shoreface and offshore processes, then a sea level fluctuation of many hundreds of meters would be required. Evidence is presented to demonstrate that the Delaware Mountain Group was deposited in cycles of high (shallow carbonate) and low (basinal siliclastics) stillstands of sea level. The Global Expansion and Contraction Cycle Hypothesis is proposed as the controlling process for the deposition of the Delaware Mountain Group as a shallow water deposit.

A history of the models of deposition for the Delaware Mountain Group is presented, and compared to the Global Expansion and Contraction Cycle Hypothesis for conflict and harmony relative to the facts of observation.

Abstract

SSAU is a mature CO₂ flood and one of the ten largest fields in the Permian Basin, with 615 MMBO cumulative production. Recent reservoir characterization integrated 12,000 ft of core, 630 wells, 3D seismic, and 40+ years’ production history into an integrated, 3D reservoir management tool. Twelve dolomitic facies range from deep subtidal argillaceous mudstone and fusulinid wackestone, to peritidal laminites and microkarst residuum. Principal reservoir facies are fusulinid dolowackstone, fusulinid-peloid dolopackstone, and coated-grain dolograinstone. Depositional facies control reservoir properties with the exception of poreplugging by late anhydrite. Five facies groups were predicted in uncored wells using fuzzy-logic constrained by available log data and vertical facies proportion curves.

A cycle-hierarchy consistent with the outcrop-based stratigraphic framework of Kerans and Fitchen was first defined in 1D and 2D from cored wells, then extended through 3D well-log correlation. Both paleo- and present-day structures are complex differential compaction features over antecedent shelf-margins and buildups. Facies maps demonstrate paleostructural control starting with crestal and ending with peripheral concentrations of grain-dominated reservoir facies. Fifteen correlation surfaces form the deterministic framework within which facies and rock properties were geostatistically distributed. A “mini-model” was up-scaled and history-matched midway through full-field modeling to test whether the model effectively captured rock properties and flow units.

Although simulation work on up-scaled models is ongoing, the 5,760,000 cell fine-scaled static model and its associated full-field correlation framework currently enhance reservoir management by facilitating: 1) remaining reserves estimates, 2) better understanding for CO₂ and water conformance, & 3) future project evaluation.

Abstract

Fullerton Field in Andrews County, West Texas, discovered in 1942, produces 42° API crude from lower Clear Fork and Wichita carbonates. Primary recovery, developed on 40-acre well spacing, had reached 107 MMSTB of oil by 1961, when waterflooding began. The field was unitized in 1953. Production peaked in 1986 at 15,000 BOPD and declined sharply to 6,000 BOPD in 2001. By the end of 2001, the unit had produced 288 MMSTB of oil with 95% watercut.

In order to identify the distribution of original resources and the location of remaining oil, a 2,000 acre study area was chosen for detailed, integrated geologic, petrophysical, and engineering characterization. This area was selected because it contains the highest density of cores, best suites of wireline logs, and appears to be most representative of the field. These data were used to build a 3-D reservoir model and conduct reservoir flow simulations.

Thirtynine rock-fabric flow layers were defined based on high-frequency cycles identified from core and wireline log studies. These flow layers are used to provide a geologically-constrained framework for 3-D modeling. A fine-scale geological model containing 3.2 million cells (140 by 90 by 256) was constructed first for the area, and porosity, permeability, and water saturation were mapped through the 3-D space. The geological model was then scaled up to a coarse reservoir model containing 130,000 cells (73 by 48 by 39) for reservoir simulation.

The simulation study has been divided into three phases: (1) sensitivity analysis, (2) history matching, and (3) performance prediction. From the sensitivity study we can rank the importance of reservoir parameters affecting production performance. Although Φh is higher in the Wichita, kh is greater in the lower Clear Fork. Because karst is common in the Wichita interval and the reservoir has been fractured by high-pressure water injection, negative skin factors (or effective wellbore radii) are used to simulate the field water injection rates. Through history matching, optimal fluid and rock properties can be determined. In the prediction phase, a variety of recovery technologies for maximizing oil recovery can be studied.

Abstract

The Suntura Field was discovered in late 1999 with the drilling of the Suntura #1 in Terry County, Texas. First production was established in early 2000 with an IP of 300 BOPD flowing. The field was initially identified on the 13 square mile Sunburst 3-D seismic survey. 32 wells have been drilled to date with 30 producers and two dry holes. Currently the field is developed on 40 acre spacing. Peak primary production occurred in late 2002 at 50,000 BOPM with the field surpassing one million barrels by November 2002.

Average pay thickness varies from 25 feet to over 200 feet. A porosity cutoff of 6% and a water saturation cutoff of 20% have been initially applied to the field area. Dolomite porosity occurs primarily in subtidal bioclastic/pelloidal packstones with numerous fusulinids, crinoinds, and brachiopod fragments. The best porous intervals are often completely dolomitized with little relic structure of original depositional facies but their position indicates well-sorted shoal facies.

The Slaughter (Lower Clear Fork) Field served as an analogy having been imaged with 3-D seismic with the acquisition of the Kingdom 3-D. This survey was shot in order to extend and further develop the Kingdom (Abo) Field, but also was designed to collect data on the lower Clear Fork. Wells drilled in the Abo field and along shelf margin were correlated and then integrated into the seismic surveys.

A hierarchical sequence stratigraphic framework was applied to the integrated data sets using the BEG’s lower Leonardinan system from Apache Canyon (Fitchen 1995). The outcrop models from Apache Canyon were used as analogs, not only to predict the position of reservoir rocks along the shelf margin but also to correlate the sequence framework. The correlation of depositional facies from outcrop to subsurface was very helpful in narrowing the search for reservoirs. Line interpretations from the walls of Apache Canyon proved to be excellent representations of the dip oriented lines from the 3-D volume.

The 3-D seismic showed a very steep lower Abo (lower L1) shelf margin with considerable accommodation space in front of the margin. This allowed the deposition of thick lowstand, transgressive and highstand systems tracts during L2 time. The top of the lower Clear Fork is picked as a peak amplitude event that corresponds to the top of the L2 Sequence (second 3^rd order sequence in the Leonardian). A peak that corresponds to the top of the lower L1 Sequence (the first 3rd order sequence in the Leonardian) identifies the top of the lower Abo.

Productive porosity in the area has a slow velocity compared to the tight dolomite and is associated with an amplitude trough immediately below the lower Clear Fork (L2) peak. Northwest of the production, the lower Clear Fork lithology is tight anhydritic dolomites which produces a low amplitude trough. As porosity develops in the section on the shelf margin the trough increases in amplitude. The trough is strongest when porosity develops approximately 100 feet below the top of the lower Clear Fork due to tuning of the peak/trough pair. In addition, the base of the porosity interval produces a moderate amplitude peak. Slow velocity argillaceous dolomites and clastics associated with transgressions will also contribute to the trough amplitude. A trough amplitude anomaly can also be associated with clastics deposited in Low Stand System Tracts (LST’s) rather that porosity. These false amplitude anomalies can usually be identified by a trough immediately above a sequence boundary that extends down into the basin

The prospective area for the lower Clear Fork in the Sunburst area was a ½ mile wide moderate to high amplitude trough anomaly that extended along the shelf margin. Near the southern edge of the survey, the trough was higher amplitude than anywhere on either survey. This was interpreted to be due to a thick section of excellent porosity since it was up on the shelf and in a HST of the L2 sequence. The anomaly was not entirely due to clastics since it was not in the LST and did not extend down into the basin.

Abstract

Imaging stratigraphic variations is critical when exploring for hydrocarbons in buried channels. As tools are developed both to increase the resolution of the image and to improve the understanding of the rock properties, it is necessary to have a known standard to test the techniques. To this end, we are generating 3-D numerical seismic data using the full elastic Brushy Canyon model developed by Mike Batzel and his colleagues. The model was developed from mapping geologic outcrops and rock properties of the Brushy Canyon in West Texas and reflects the complexity of the channels in the region.

Using software developed by Lawrence Livermore National Laboratories, we are able to acquire numerical seismic data over large, complex models. By accessing 36 nodes of the Sun cluster at the University of Houston, it is possible to run one shot per day. With the software, we are able to record the three components of motion and the compressional energy on the surface of the model. In generating these data, we will be able to provide the exploration industry with a known standard for aid in the development and calibration of seismic technologies including elastic inversion, 3-D AVO, spectral decomposition, and seismically driven reservoir characterization.

Abstract

An examination of the Pennsylvanian Virgilian limestones in a well presently producing from deeper Pennsylvanian Morrow sandstone revealed an interesting porous limestone interval from 4387 feet to 4430 feet. The lower part of this porous interval (4396 feet to 4430 feet) has neutron-density porosities (Φnd) from 6% to 16% with deep resistivity (ILD) values from 1.9 ohm-m to 13 ohm-m. In addition this interval has a wet resistivity invasion profile (FL>ILM>ILD). However, there is an upper porous interval from 4387 feet to 4394 feet with very high neutron-density porosities (Φnd = 18% to 28%) and much higher deep resistivities (ILD up to 19 ohm-m; 22.8 ohm-m when thin bed corrected). If the upper interval is wet the resistivity should be less than the lower interval because the porosity is greater.

The formation water resistivity (Rw) was calculated for the Virgilian porous interval using both the SP and Rwa methods. Both methods resulted in Rw values of 0.039 at formation temperature. Conventional log analysis of the upper interval at a depth of 4388 feet resulted in a neutron-density porosity(Φnd) of 28%, an Archie Water Saturation (Swa) of 14.8% (a=1 and m=n=2), and a bulk volume water (BVW) of 0.041. Using just a conventional analysis the Virgilian porous interval from 4387 feet to 4394 feet looks like behind-pipe pay. However, additional log analysis at a depth of 4388 feet resulted in a sonic porosity (Φs) of 16%, a Moveable Hydrocarbon Index (Sw/Sxo) of 0.53, a Ratio Water Saturation (Swr) of 45.2%, and a resistivity porosity (Φrxo) of 8%. The additional log analysis indicates that the upper porous interval has vuggy porosity, and because Φs>>Φrxo, the porosity is probably oomoldic.

In contrast to the upper porous interval the lower interval at depths of 4400 feet and 4420 feet have neutron-density porosities (Φnd) of 16% and 9%, sonic porosities (Φs) of 14% and 10%, and resistivity porosities (Φrxo) of 17% and 10%. The general agreement in the porosities indicate the presence of intergranular porosity. Therefore, the increase in deep resistivity values from the lower porous interval (4396 feet to 4430 feet) to the upper porous interval (4387 feet to 4394 feet) is not the result of the presence of hydrocarbons, but is the result of a change in carbonate pore type from intergranular porosity (4396 feet to 4430 feet) to oomoldic porosity (4387 feet to 4394 feet).

An examination of the mud log indicates that the upper porous interval (4387 feet to 4394 feet) is a limestone with oomoldic porosity, some speckled yellow fluorescence (no cut) and no gas shows. The lower porous interval (4396 feet to 4430 feet) is a limestone in part oomoldic with no mud log shows. The upper porous interval is not a behind-pipe pay zone, because an oomoldic carbonate with no hydrocarbon shows and a BVW value of 0.041 should produce only water.

Abstract

The Yates Formation in the Permian Basin, Texas contains an under-exploited gas resource. Little research or commercial effort has been directed at examining incremental gas production opportunities such as for the Yates Formation. Gas from the Yates Formation historically has been under-exploited in lieu of deeper occurring oil reservoirs and has been produced and sold at a discount due to its high nitrogen content (15-20% nitrogen) and low pressures. Regional use of this gas as a fuel source for gas-fired turbines or mixing of the high nitrogen gas with other low nitrogen gases may increase its value and market. More detailed stratigraphic and reservoir characterization efforts are essential for designing efficient production strategies.

While the importance of cores to calibrate wireline log data is obvious, it is especially crucial in interpreting the lateral variations within the Yates Formation. Integrated log data and core studies of the Yates Formation from Ward-Estes, North Field, Ward County provide a basis for interpreting Yates facies and lithologies from wireline logs. Low gamma ray signatures in Ward-Estes, North Field wells correspond to intervals of thin dolomite and thick anhydrite. By contrast, cores in Kermit Field, Winkler County and Embar Field, Andrews County reveal that low gamma ray values represent thick intervals of halite, as well as the aforementioned dolomite and anhydrite. These data support a regional trend of increasingly more open marine facies in Yates sediments to the south and west in the Permian Basin.

Deposition within the Yates Formation is a function of cyclic marine flooding over shallow water exposure surfaces or tidal flats. Cycle bases are defined by marine sediments, such as dolomite, anhydrite and, halite, deposited during marine transgression. Lateral variations in lithology are probably due to local variations in marine circulation and topography. Cycle base marine units are (1) cryptalgally laminated, (2) brecciated due to solution collapse brecciation, (3) composed of well sorted, rounded rip-up clasts, or (4) karsted due to dissolution. Cycle tops are defined by thinly bedded, highly porous, fine-grained eolian sandstone to siltstone. Sandstone units are highly (1) haloturbated, (2) well bedded, or (3) massively bedded (rare). Although facies and thicknesses vary somewhat laterally, cycles are generally laterally continuous over large areas and relatively planar.

The contact between the Yates Formation and the underlying Seven Rivers Formation is gradational due to an overall regional decrease in accommodation as defined by the thinning of marine units and the thickening of eolian units. The upper contact of the Yates Formation and the overlying Tansill Formation is relatively sharp. This contact is interpreted to be the result of a large-scale marine transgression. The carbonate/anhydrite deposits that mark this flooding event are defined by an obvious gamma ray log response. Consequently, this contact is used as a regional correlation marker bed.

Abstract

The Permian Basin of West Texas and southeast New Mexico, the largest petroleum-producing basin in the United States, contains an estimated 23% of the proved oil reserves in the United States. This region has the biggest potential for additional oil production in the country, containing 29% of estimated future oil reserve growth. Only 28% of the estimated 106 Bbbl of original oil in place in the Texas part of the basin has been produced. Play-based analysis of reservoir characteristics and preferred management practices in Permian Basin oil fields should have a substantial impact on domestic production.

A project is under way to (1) develop an up-to-date, digital portfolio of oil plays in the Permian Basin of West Texas and southeast New Mexico, (2) study key reservoirs from some of the largest or most active plays to incorporate information on improved practices in reservoir development in the portfolio, and (3) widely disseminate the play portfolio to the public via CD, the Internet, and other techniques. The play portfolio will group into plays all reservoirs in the Permian Basin having cumulative production >1 MMbbl and summarize key reservoir characteristics and preferred management practices of each play.

Approximately 1,000 reservoirs in the Texas part of the Permian Basin had produced 1 MMbbl of oil through 2000. These reservoirs have been grouped into 25 geologic plays. The plays with the highest cumulative production are the Northern Shelf Permian Carbonate, the Grayburg (Upper Permian) Platform Carbonate, and the Pennsylvanian Horseshoe Atoll plays.

Abstract

The oil-producing Ordovician Ellenburger Group has undergone extensive karstification and is also fractured. Although diagenesis and burial history of Ellenburger Group dolostones have been studied previously, the relative timing and interaction of fracturing events and karstification have been largely neglected. In dolostones affected by karstification, distinction between fractures related to local paleocave collapse and those produced by regional tectonic processes is difficult. Fracture patterns related to these two types of process are likely to be markedly different, even though individual fracture morphologies may be similar.

In this study, well logs and sidewall cores from open-hole intervals in two ≥45-year-old wells in Ellenburger Group dolostones from Barnhart field, West Texas were utilized, together with a full-diameter core and image log from a recently drilled well. Fracture sets were characterized in terms of orientation and intensity. Fractures with consistent orientations that crosscut clasts and matrix in paleocave-collapse breccias postdate at least one phase of cave collapse. As a first step in attempting to unravel the history of these rocks, an intensity analysis was conducted on these relatively late fractures

Fractures with apertures ranging from several microns (microfractures) to a few millimeters (macrofractures) were imaged using conventional and scanning-electron-microscope-based cathodoluminescence (SEM-CL) and aperture-size distributions were measured. Such distributions can be extrapolated to predict likely intensities of macrofractures where these have not been sampled in the well bore. SEM/CL also revealed that fractures have a distinct morphology indicating that they formed by propagation along rhombohedral dolomite grain boundaries. At least three different dolomite types were recognized due to their contrasting luminescence. One type of dolomite dominates the host rock, a second type precipitated during fracturing, and a third type precipitated during and after the two main sets of fractures developed. Calcite cement is also present and mostly postdates fracture opening.

Abstract

The Global Expansion and Contraction Cycle Hypothesis is based on the assumption that an increase or decrease in the radius of the Earth increases or decreases, respectively, the fracture volume of the mantle’s crust. It is assumed that an increase in fracture volume will passively be filled with ocean water. The predicted result is a worldwide regression during the global expansion phase of a cycle. Conversely, a decrease in the Earth’s radius will decrease the fracture volume of the Earth, resulting in a worldwide transgression during the global contraction phase of a cycle. Continued contraction will result in mountain building.

The Cycle Hypothesis provides a process for regression and transgression cycles (the basic unit of modern sequence stratigraphy) with sea level fluctuations from a fraction of a meter to greater than 11 kilometers. Based on a simplified set of assumptions, an increase in the present radius of the Earth of 2.75 kilometers will drain all of the world’s oceans into the dilation fractures including the ocean trenches, ocean lineaments, and ocean transform faults.

Calculations are shown whereby the required change in the Earth’s radius that could result in the required order of magnitude eustasy during Guadalupian time to transport and deposit sediments of the Delaware Mountain Group as a fluvial to shallow marine deposit.

The Hypothesis is in conflict with the following ideas and hypotheses: the Earth has a solid iron and nickel inner core; the solid mantle has had convection cells; turbidity and density currents are capable of erosion in water depths greater than 150 meters; the subduction mechanism for the hypothesis of plate tectonics; an ever increasing radius of the Earth; a constant radius of the Earth; transform faults are due to strike-slip motion, and the process of spallation in the upper atmosphere of the Earth is the source of natural deuterium and tritium in the Earth’s oceans.