Two fields, Ozona (Canyon) and Sawyer (Canyon), with more than 4,000 total wells, contain the majority of wells in the Canyon Sand trend of Crockett, Edwards, Schleicher and Sutton Counties in Southwest Texas. Average ultimate recovery for the fields decreased from 1,100 MMCF/well for wells drilled in 1970 to 400 MMCF/well for wells drilled in 1985, then remarkably reversed the trend. Recently drilled wells (since 1991) are expected to recover an average 625 MMCF. Initial monthly production decreased from 15,000 mcf/month to 5,000 mcf/month in 1985 and then increased to the present 12,000 mcf/month. Average first year wellhead pressure continued to decrease throughout the 25 years studied to a present 1300 psig in Ozona and 700 psig in Sawyer. The data suggest that drainage interference began to be a factor in about 1985 in the more densely developed areas. Although the average well density was about 200 acres per well in 1985, the true density in areas of active infill drilling probably approached 120 acres per well. Present average density is 143 acres per well in Ozona Field and 131 acres per well in Sawyer Field, but many leases are developed on density of 80 acres or less.
During the 1970's, the Canyon Sands of Crockett, Edwards, Schliecher and Sutton Counties, Texas became a significant source of new gas production (Figure 1). More than 4,000 productive wells have been completed in the Sawyer and Ozona Fields. Drilling activity since 1970 has varied, peaking in the mid to late 1970's and falling to a low in 1986 as gas demand from these fields fell.
As development of the trend proceeded and fields merged, the Texas Railroad Commission ordered a number of the adjacent fields reclassified into either Ozona (Canyon Sand) Field or Sawyer (Canyon) Field. The two fields now contain more than 65% of the wells in the entire 6,000 well Canyon Sand gas trend.
Sawyer (Canyon) Field was discovered in 1967 and produces gas from Pennsylvanian age deltaic or turbidite lenticular sands at about 5,200 to 6,500 feet. The field covers portions of Edwards, Schleicher and Sutton Counties, and contains some 2,200 active and abandoned wells. Ozona (Canyon Sand) Field is located almost entirely in Crockett County, west of the Sawyer Field, and trending deeper into the Val Verde Basin at about 6,500 to 7,500 ft. It was discovered in 1962, but, like Sawyer, was slow in development until the rise of air drilling in the early 1970's. Figures 2 and 3 show the development history of each field group.
Both fields produce dry gas with small amounts of water from tight sands of 8-10% porosity and less than .1 md permeability1. There is core evidence that 1-2 inch streaks of significantly greater permeability exist within the larger sand lenses and these may enable the sands to produce in economic quantities.
A study of estimated ultimate recovery, initial production rates, wellhead pressures, and well density was completed for each field. The study encompassed all 3,200 wells drilled since 1970 in the two Fields. The Ozona group of 1,270 wells included minor numbers in the adjacent fields of Ozona, NE (Canyon 7520), Ozona, North (Canyon), Ozona NW (Canyon) and Ozona, SW (Canyon, Lower). The Sawyer Field study of 1,950 wells included only those classified in Sawyer (Canyon) Field.
Conformance control is any action taken to improve the injection or production profile of a well. It encompasses procedures that enhance recovery efficiency, improve wellbore/casing integrity, and satisfy environmental regulations. Unwanted fluid production in oil- and gas-producing wells is a limiting factor that controls the productive life of a well. The cost of produced water disposal in an environmentally non-threatening fashion may be a major concern for many producers. In addition, control of excess water and gas production improves profitability by allowing additional oil to be produced.
Application of water control technology assists to minimize water production and maintain the oil flow rate of a well. Reservoir engineering and well testing play essential roles in characterizing and detecting the problems associated with producing formations and wells.
This paper starts with problem identification in both producing and injection wells. It then covers the behavior and control of several types of reservoirs with different drive mechanisms. Applications of reservoir simulation and well testing in the control of water and gas coning, determination of the amount and the best appropriate treatment application, effect of formation layering, control of relative permeability to water, application of permeability blocking agents, water channeling, secondary recovery, viscous fingering, and polymer flooding are detailed in this paper. In additional several techniques to evaluate the overall success of a conformance control procedure are presented.
The purpose of this paper is to identify reservoirs associated with excessive gas or water production and to recommend the proper remediation. Conformance control begins with identifying the source of problem. This requires a thorough investigation of all aspects of well and reservoir parameters. The following is a list of some of the parameters required for identification of the reservoir performance problems.
Reservoir permeability and porosity
Relative permeability to oil, water, and gas
Connate water and irreducible oil and gas saturations
Net formation height
Oil, gas, and water production rates versus time
Original water-oil contact
Length of time before water production began
Location of all perforations
Fraction of the productive interval completed
Identification of fluid entry locations and the type of fluid entering wellbore (production logging)
Location and continuity of any shale layers
Identification of cement to casing bonding (bond log)
The application of cyclic CO2, often referred to as the CO2 Huff-n-Puff (H-n-P) process, may find its niche in the maturing waterfloods of the Permian Basin. Coupling the CO2 H-n-P process to miscible flooding applications could provide the needed revenue to sufficiently mitigate near-term negative cash flow concerns in these capital intensive projects. Initial results from a field demonstration of the process are provided. The paper briefly reviews the reservoir characterization associated with the project and the compositional simulation of the CO2 H-n-P process. Simulation results suggest that reservoir characterization of flow units is not as critical for a CO2 H-n-P process as for a miscible flood. Entrapment of CO2 by gas hysteresis is considered the dominant recovery factor for a given volume of CO2. The repetitive application of the process was found to be unwarranted in a waterflooded environment. Future history matching of the performance will allow better forecasts and evaluation of the economic impact available with this underutilized process.
The CO2 H-n-P process is a proven enhanced oil recovery technology in Louisiana-Texas Gulf-Coast sandstone reservoirs.1,2 Application seems to mostly confine itself to low-pressure sandstone reservoirs.3 The process has been shown to be moderately effective in conjunction with steam on heavy California crude oils.4,5 A review of earlier literature1,6,7 provides an excellent introduction to the theory, mechanics of the process, and several case histories. Although the technology is proven in light oil sandstones, it continues to be a very underutilized enhanced recovery option for carbonates. However, the theories associated with the CO2 H-n-P process are not lithology dependent.
A significant amount of oil reserves are located in carbonate reservoirs. Specifically, the carbonates deposited in shallow shelf (SSC) environments make up the largest percentage of known reservoirs within the Permian Basin of North America. Many of these known resources have been under waterflooding operations for decades and are at risk of abandonment if crude oil recoveries cannot be economically enhanced.8,9
Miscible CO2 flooding is the process of choice for enhancing recovery of light oils10 and already accounts for nearly 12% of the Permian Basin's daily production.11 There are significant probable reserves associated with future miscible CO2 projects. However, many are marginally economic at current market conditions due to large up-front capital commitments for a peak response which may be several years in the future. The resulting negative cash-flow is sometimes too much for an operator to absorb. The CO2 H-n-P process is being investigated as a near-term option to mitigate the negative cash-flow situation - allowing acceleration of inventoried miscible CO2 projects.
Microbial cultures can be used to reduce or eliminate scale formation in water flood injection systems. Several water floods have been treated for over a year with microbial culture products and the effects of the treatment on operating performance has been studied. The injection systems initially showed significant scale problems from calcium sulfate and calcium carbonate. Tracking water flood performance parameters such as injection pressures and volumes over the treatment period showed that, as compared with prior treatment historical data, a variety of positive results of treatment were evident. For example, the flood injection volumes were stabilized or increased, injection pressures were stabilized and oil and gas production was increased. Laboratory studies of injection water showed that filtration times could be significantly reduced by microbial treatment, indicating that near well-bore occlusion could be reduced by such treatments. The microbial treatments were considered more effective than prior alternative treatment technologies. This new technology offers a cost-effective superior alternative to conventional technologies.
Secondary recovery operations utilizing water flooding represent the majority of oil fields in the United States. The practice is particularly common in mature producing regions such as the Permian Basin. The handling of the large volumes of water used in such projects leads to specific operational problems related to water chemistry. Demand for water leads to the use of various aqueous sources which may contain differing amounts of cations and anions. These incompatible waters lead to the formation of mineral salt deposits such as calcium carbonate, calcium sulfate, barium sulfate or iron sulfide. These deposits may form at any point in the injection system from surface facilities to downhole. Occlusion of water injection wells by either preformed or in situ formed scale is a principal cause of reduced water flood efficiency. Skin damage and blockage of the formation by scale leads to decreased injection volumes and increased injection pressures. The former instance may reduce injection volumes and the latter increases operating costs.
Conventional treatments for injection system scale include acid and chemical treatments. Both technologies suffer from significant drawbacks. Acid treatments can promote corrosion, utilize a hazardous chemical and require significant downtime. Acid alone is not effective on calcium or barium sulfate scale. Chemical treatments are expensive and may not be cost-effective or successful. They may also not be successful in treating downhole permeability problems. An alternative technology is the use of microbial culture products to improve water flood operations.
Production data represent a source of information about the ongoing dynamic flow process in the reservoir. A proper analysis of these data might therefore give an indication of the relationships governing the fluid flow. Exploratory data analysis is one tool which can be used to extract the required information and to establish a statistical significance to the results. This paper presents a simple approach to examine the interwell communication and interference of a mature waterflood in order to identify and rank areas of potential improvement. Using this as a screening process we can identify areas with the best potential for further and more detailed studies. In addition some of the problems and limitations associated with analysis of production data are discussed.
Is there an easy way of evaluating waterflood performance based solely on surface measurements in the form of rates and pressures? Although production data have always been a key part of any waterflood evaluation, no good answer has been given to what we can expect to get from such an analysis.
Exploratory data analysis of production data is aimed at organizing and representing the data in an easy interpretive way. The analysis can take place at two levels, global and local. The global level will examine large scale trends (multiple wells), whereas the local analysis will focus on single well behavior and interwell relationships (well pairs). The use of production data as an analytical tool depends upon the quality and density of the data. More data of higher resolution and quality will yield significantly more information than irregular and poorly measured data. The quality of the analysis is therefore a direct function of the quality and the density of the measurements.
The analysis of production data poses a particular challenge since we have a 3-dimensional data set mixing both the spatial and the temporal (time) dimensions. Stationarity assumptions along the spatial plane do not translate into stationarity along the temporal axis. Special care is therefore necessary when dealing with both the spatial dimensions and the temporal dimension simultaneously. In addition, the surface measured production data constitute a 2-dimensional spatial plane, which represents the dynamic behavior of a 3-dimensional reservoir. Another challenge is the size of the data set which comprises the production data. An efficient handling and representation is therefore important to obtain a clear interpretation.
The primary objective of the methodology presented in this paper is to screen the field data to identify and rank areas of potential production improvement for a mature waterflood, in the form of changes to the individual wells, operational changes to the water injection allocation, infill drilling or pattern reorientation. This identification process depends upon the ability to extract information about the connectivity, sweep and interference among injection and production wells based on production data. Having identified potential areas of improvement, these areas can be further evaluated based on the geological knowledge and a more detailed reservoir study.
This paper addresses mathematical modeling of free-fall gravity drainage which is believed to occur in naturally fractured reservoirs after depletion of oil in the fractures or gas injection into the fractured system. Comparison of wetting phase recoveries calculated using existing mathematical models with experimental data indicates the inaccuracy of these models. The causes of error are identified to be the unrealistic assumptions made in formulation of the models. Based on Darcy's law and film flow theory, we have developed a new mathematical model to describe the free-fall gravity drainage process. A simple non-linear governing equation for phase demarcator in dimensionless form was formulated and solved numerically as a function of dimensionless time. Based on the dimensionless demarcator, fluid recovery during free-fall gravity drainage is calculated. Comparisons of wetting phase recoveries given by the new model with 20 sets of experimental data obtained under thermodynamic equilibrium conditions for a variety of fluids and cores show much better accuracy of the model over the existing models. Using the dimensionless time, tD = ke gt/ L, fluid recovery obtained from laboratory studies can be scaled to field applications for estimation of projected oil recoveries in oil fields. We have also applied the new model to simulation of free-fall gravity drainage under non-equilibrium conditions where molecular diffusion between phases is considered. Experimental oil recovery data obtained from CO2 injection into a Berea core and a reservoir sandstone core, which were saturated with separator oil, have been matched by the model using empirical correlations for fluid properties. The objective of this paper is to provide reservoir engineers with a useful tool for estimating the oil recovery from fractured reservoirs after gas injection.
Because fractures are highly conductive to gas and gas is the nonwetting phase in the rock matrix, gas injection into fractured reservoirs has been traditionally considered as an inefficient method for enhancing oil recovery from fractured reservoirs. However, the Midale Pilot indicated that the efficiency of CO2 injection into fractured reservoirs is not as low as expected. The only explanation is that when a non-equilibrium gas is injected into the fractured system at elevated pressure, compositional effects become active between the gas in the fractures and oil in the matrix. Due to multi-contact mechanism, light hydrocarbons in the oil can be extracted from the virgin oil bank forming a "gas" -rich light liquid phase and an oil-rich heavy liquid phase. This kind of phase split has been reported by several investigators including Lansangan and Smith. The interfacial tension (IFT) between phases is low compared to that between virgin oil phase and gas phase. Therefore, the capillary pressure threshold may be overcome by gravity resulting in gravity drainage of the light oil from the matrix blocks. In order to understand the mechanism of gravity drainage and predict the response of fractured reservoirs to gas injection, a mathematical model of the process is desirable.
Equilibrium Gravity Drainage. Studies on gravity drainage were conducted a century ago when King investigated the principles and conditions of aquifer motion. Investigations of gravity drainage of oil in oil reservoirs were initiated in early 40's of this century. Leverett and Katz presented data and discussed the theory relating capillary and gravitational forces acting on liquids contained in a sand body. Stahl et al. conducted experiments to investigate behavior of free-fall gravity drainage of water and oil in an unconsolidated sand. Elkins et al. presented a simplified theory of regional drainage of oil from upstructure location to downstructure location due to gravity assuming zero capillary pressure gradient. Cardwell and Parsons presented a governing equation for the free-fall gravity drainage process. They could not solve the equation because of its non-linearity. P. 23
Large-scale CO2 projects, like those implemented more than a decade ago in the Wasson Field, are not as attractive today because of large capital investments up-front and lower and uncertain oil prices. However, building upon our experience in large-scale floods, as well as recent improvements in the reservoir characterization and simulation technology, a grass-roots CO2 project can still be made attractive, in today's environment, by high-grading the reservoir resources, staging the development, and re-injecting the produced gas without facilitating a large gas processing plant. The paper contrasts the characteristics of the Bennett Ranch CO2 project, a CO2 flood designed today, with traits of CO2 floods of yesteryear. The paper also highlights the innovative efforts in reducing and delaying the capital expenditures for wells and facilities, resulting in a less than 1 MM$ capital investment prior to the CO2 injection. Due to small flood patterns, significant production responses have been observed after only 3 months of CO2 injection.
The Bennett Ranch Unit (BRU) is located in the northeastern portion of the Wasson Field which produces oil from the San Andres formation. (See Figure 1) The unit was formed in 1964 to install a waterflood. Historically, the unit production reached 12,100 bopd in 1974, but by 1994 production had steadily declined to 3000+ bopd. Currently, the unit-wide-average oil cut is around 6% but it varies areally from below 4% in the most mature southern area to above 10% in the north. Many wells in the southern area have been shut-in due to high water cut. In June 1994, cumulative primary and secondary recovery reached 104 mmbo. CO2 flooding is considered the only viable option to extend the field life.
San Andres Reservoir Description
The San Andres formation is a mid-Permian aged dolomite located at depths ranging from approximately 4800' to 5600'. Structurally, the San Andres at BRU forms a northeast plunging anticline (see Figure 2) with an average elevation approximately 350' below the highest stratigraphic equivalent interval of the Wasson field (which is located in the Denver Unit). As a result of this low structural elevation, there is no gas cap at BRU. Within the unit, the San Andres formation dips approximately 4.5 degrees on the eastern flank and 1.5 degrees on the western flank.
The San Andres reservoir at BRU can be stratigraphically divided into two major intervals: "First Porosity" and "Main Pay." The deeper Main Pay interval consists of dolomitized open marine packstones and grainstones and possesses better reservoir properties than the First Porosity does. The First Porosity interval was deposited in a more restricted marine intertidal environment; it has a finer crystalline matrix and is less continuous than the Main Pay. Supratidal mudstones and anhydrites that lie above the First Porosity interval form the seal for the hydrocarbon accumulation. Based on the character of gamma ray and sonic logs, we have subdivided the First Porosity interval into a single interval (F1) and the Main Pay into 6 zones (M1-M6) (see Figure 3).
AbstractA gravity-stable, vertical CO2 miscible injection flood was implemented in the 824 feet thick Wellman Unit Wolfcamp reef reservoir in July 1983. CO2 is being injected in the crest of the reservoir to displace the oil vertically downward. The producing wells are constantly being plugged down out of the "gassed out" interval into the oil bank. The purpose of this paper is to present the results of the PND®-S through tubing logging tool as a method to determine the CO2/oil/water contacts and the use of multiple inflatable packers/sliding sleeve plugdown assemblies to achieve zonal isolation between "gassed out" intervals and producing intervals.
Underbalanced drilling has been utilized with increasing frequency to minimize problems associated with invasive formation damage which often greatly reduce the productivity of oil and gas reservoirs, particularly in open hole horizontal well applications. Underbalanced drilling, when properly designed and executed, minimizes or eliminates problems associated with the invasion of particulate matter into the formation as well as a multitude of other problems such as adverse clay reactions, phase trapping, precipitation and emulsification which can be caused by the invasion of incompatible mud filtrates in an overbalanced condition. In many underbalanced drilling operations, additional benefits are seen due to a reduction in drilling time, greater rates of penetration, increased bit life, a rapid indication of productive reservoir zones and the potential for dynamic flow testing while drilling.
Underbalanced drilling is not a solution to all formation damage problems. Damage due to poorly designed and/or executed underbalanced drilling programs can rival or even greatly exceed that which may occur using a well-designed conventional overbalanced drilling program. Potential downsides and damage mechanisms associated with underbalanced drilling will be discussed. These include:
Increased cost and safety concerns.
Difficulty in maintaining a continuously underbalanced condition (due to such factors as pipe connections in rotary drilling, bit trips, mud pulsed logging, bit jetting and flushing effects, localized depletion and subsequent repressurization effects, poor knowledge of initial reservoir pressure, multiple zones with differing initial pressures, slug flow and liquid holdup in the vertical section of the wellbore, frictional pressure drop and mechanical problems with surface equipment or gas supply sources).
Spontaneous imbibition and countercurrent imbibition effects.
Glazing, mashing and cuttings induced damage.
Macroporosity gravity induced invasion.
Difficulty of application in zones of extreme pressure and permeability.
Political/career risk associated with championing a new and potentially risky technology.
This paper discusses reservoir parameters required to design an effective underbalanced or overbalanced drilling program, laboratory screening procedures to ascertain the effectiveness of underbalanced drilling in a specific application and presents screening criteria with respect to the types of reservoirs which present good applications for underbalanced drilling technology.
The Lost Soldier Tensleep field tertiary performance has a noteworthy case history that demonstrates how an incremental 13% of original oil in place will be recovered from this sandstone reservoir using carbon dioxide. Located in south central Wyoming, the Lost Soldier Tensleep has been under carbon dioxide (CO2) injection since 1989. From 1989 through 1995, a 61% hydrocarbon pore volume (HCPV) slug of CO2 was injected into the reservoir to recover an incremental 13.6 million barrels of tertiary oil. Prior to CO2 injection, the reservoir was producing 2,500 bopd at a 97% watercut. Within one year, oil production exceeded 10,000 bopd and is currently 6,000 bopd.
Since its start-up in 1989 with 47 producers and 40 injectors the subject flood has used a water-alternating-gas (WAG) method and line drive pattern to process approximately 840 acres of reservoir. Illustrations of actual WAG injection cycles and resultant offset production response are included in this case history. The Lost Soldier flood has been so successful that one producing well had an incremental rate of 1700 bopd, carrying the unique distinction of having the highest peak incremental CO2 response that the authors could find documented in U.S. literature.
Information contained in this paper provides observations and conclusions about field performance optimization as well as reservoir management philosophy. Several actions were completed during the early to mid-1990's to maximize recovery and profitability. These included maintaining miscible reservoir pressure, increasing natural gas liquid recovery, converting to sour reinjection, and exploiting downdip oil potential.
The Lost Soldier Tensleep field is located in the Great Divide Basin of Wyoming approximately 40 miles northwest of the city of Rawlins (Figure 1). Lost Soldier is the larger of two fields located near the town of Bairoil, Wyoming, the other being Wertz field. Combined Lost Soldier and Wertz field production is 10,000 bopd and 1,500 bbl/day of natural gas liquids. The majority of current production comes from the Pennsylvanian age Tensleep and the Mississippian age Madison carbonate. The original oil in place (OOIP) in all horizons in both fields approaches 1 billion barrels.
Currently, besides the Lost Soldier Tensleep, CO2 is being injected into the Wertz Tensleep1 and the Lost Soldier Darwin/Madison reservoirs.
CO2 for the Bairoil fields is supplied from Exxon's LaBarge project2. The CO2 is transported via pipeline 120 miles from its Shute Creek plant in southwest Wyoming to a point 19 miles northwest of Bairoil, where it is transferred to an operator-owned spur line for final delivery.
Field History and Development
The Lost Soldier Field was discovered in 1916 when Bair Oil Company drilled a well 265 feet into the first Frontier formation. The well produced 200 bopd. The Dakota, Lakota, Morrison, and the Sundance sands were discovered prior to l9263. In 1930, the Tensleep was discovered, and the initial well flowed 2,435 bopd. In 1947, the Darwin sandstone and Madison carbonate were discovered and produced at a combined rate of 1,045 bopd. In 1948, the Flathead sandstone was discovered immediately above the granitic basement. Amoco purchased the properties in 1975.
Development was slow for the Lost Soldier Tensleep until 1942. During the early 1940's, 16 wells were completed, producing between 2,500 and 8,000 bopd. Since its discovery, the Tensleep has been the most prolific of the nine productive horizons in the Lost Soldier Field. Primary production is attributed to a combination of fluid expansion, water influx, and gravity drainage. Peripheral water injection began in 1962, and pattern waterflood was initiated in 1976. The pattern development in the late 1970's resulted in a 16 acre north to south line drive pattern still used today.
Cumulative production from the Lost Soldier Tensleep through 1995 is 120 million barrels of oil (50% of OOIP).