This paper will provide a case study of the evolution of the drilling systems and techniques used to redevelop a dolomite formation located in the Indian Basin Field, Eddy County, New Mexico, USA.This study will compare data on wells drilled by Kerr-McGee over the past five years in this field where gas productivity ranges from 1000 MCFPD to 10,0000 MCFPD per well from the Upper Pennsylvanian (U. Penn) Cisco and Canyon formation. The following drilling fluid systems utilized to drill 16 subject wells will be discussed:Conventional. Four wells were drilled using conventional water based drilling fluids. When mud loss was encountered in the U. Penn, lost circulation materials (LCM) were used to regain and/or maintain circulation.Drilling "blind" or "dry". Two wells were drilled with this modification of the conventional system. Once returns were lost, an initial attempt was made to regain returns with LCM pills. If this did not restore returns, fresh water was pumped down the drill string to keep the bit face cleaned and drilling would proceed to total depth.Air/Mist. Three wells were drilled using this medium. A string of casing was set prior to drilling into the U. Penn. An air/mist system was then utilized to drill to total depth. The well was completed open hole."Aphron" drilling fluid. This method was similar to the conventional drilling operation, but the drilling fluid system was converted to an "energized air bubble" mud system prior to drilling into the main pay. A total of seven wells were drilled with this system. Background The Indian Basin Upper Pennsylvanian field is a large field covering approximately fifty-seven 640 acre sections located approximately 20 miles from Carlsbad in Eddy County, southeastern New Mexico, USA (Figure 1). It is one of the few fields in New Mexico that has been developed on section spacing. This was feasible due to the extreme permeability of the reservoir rock. The field was discovered by the Ralph Lowe No. 1 Indian Basin test, which was completed on February 5, 1963. The Upper Penn section, occurring at a depth of about 7,500 feet, consists of approximately 85% carbonates. Within the productive limits of the reservoir 80 to 90% of the carbonates are dolomite and the remainder is limestone which appears at the base or top of the section. Shales or marlstones appear throughout the dolomite but probably make up no more than 15% of the total section. The possibility of these shale stringers causing zonal isolation fieldwide has been investigated and is unlikely. Porosity in the dolomite is highly variable ranging from intercrystaline pores to vugs and caverns (Figures 2, 3). The extent and frequency of vugular porosity zones is very difficult to determine, but it is reasonable to expect some continuity of the vugular zones. The average pay thickness is 207 ft and the maximum pay thickness is 319 ft1.

E@mesent~, have not b-n re~ewsd by the -Iew of Petroleum Engineam and are subject to wrracfii by the author(s). The materiel, se presented, does not necessarily reflaaf any posifii of the Sociity of Petroleum Engineers, hs offkars, or members. Papers presented at SPE meetings are subject to publkafion review by Edhorial Committees of the Society of Petroleum Engineers. Permission to mpy la restricted to en abatraot of not mora then~words, Illustrations may not be cop&d. The ebafraof shoufd contain cmnapkwous eoknowledgment of where and by whom the papar is presented, Write Librarian, SPE, P.O. @x 6SS636, Richardson, TX 76062=36S6, U.S.A. Telex, 1SS245 SPEUT. Hydrate Formation/inhibitionDuring Deepwater Subsea Completion Operations SK 28477 the mud line. Shut-in conditions also could 3. require chemical injection below the mud line.

Summary This paper summarizes a waste-gas treatment system designed to control emissions from thermal EOR wells. This case study discusses the need, design, installation, and operation of the system. Introduction Thermal EOR operations that use cyclic and continuous steam injection into the reservoir generate return vapors. Controlling these vapors offers environmental and operational benefits. This paper discusses the construction and operation of a wellbore-vapor-recovery system. Oryx Energy Co. operated about 934 wells in the Midway-Sunset field under casing-vapor-recovery systems (CVRS's). Emissions collected from well-casing vent gas contain hydrocarbons and hydrogen sulfide. Emissions are collected and processed through CVRS skids composed of processed through CVRS skids composed of condensers, compressors, and pumps that separate fluids from the waste-gas stream. Noncondensible gas is then incinerated to reduce hydrocarbon and sulfur emissions into the atmosphere. About 160,743 Ibm/D of hydrocarbon and 3,558 lbm/D of sulfur dioxide (SO2) are removed from the atmosphere from wells contained within these Oryx-operated systems. These hydrocarbons yield about 550 BOPD. The system helps manage the pressure differential from the reservoir into each wellbore and helps improve ambient air quality in Kern County, CA. Field History The Midway Sunset field is in the southwest corner of the San Joaquin Valley in Kern County (Fig. 1). The field extends southeast from the town of McKittrick along the Temblor Range foothills for more than 25 miles to the town of Maricopa. The field has an average width of 3 1/2 miles and encompasses more than 50,000 acres. It is the second largest oil-producing field in California and is one of the largest fields in terms of reserves within the continental U.S. About 155,000 BOPD is produced from 9,200 wells in the field. The arid topography varies from gently sloping alluvial fans to smoothly rounded hills, occasionally split by gullies. Surface elevations range from 500 to more than 1,700 ft above sea level, with the productive interval occurring from just below the productive interval occurring from just below the surface to depths below 2,000 ft. The Potter formation, a heavy-oil reservoir with oil Potter formation, a heavy-oil reservoir with oil gravities ranging from 9 to 12deg. API, is the field's primary producing zone. The first recorded oil well was drilled before 1890. The first spectacular gusher, recorded in 1909, was located near Fellows, CA, and flowed in excess of 3,000 BOPD. By 1916, more than 100 gushers flowing more than 1,000 BOPD had been placed on production. Since then, reservoir pressures production. Since then, reservoir pressures have declined, and now artificial lift is required to assist fluids to the surface. Development of the field increased drastically around 1960, with greater demand for low-gravity crude and the development and refinement of thermal recovery techniques, such as firefloods, cyclic steaming, and more recently, continuous steam injection. Thermal recovery is a process in which heat is intentionally introduced into a subsurface accumulation of organic compounds to recover fuels through wells. The primary thermal enhancement technique initiated within the Midway Sunset field in the 1960's was injection of steam into wellbores. Generally, 1 bbl of crude oil or its equivalent is fired in a steam generator and the steam is injected into the reservoir to produce about 10 bbl of crude. Heat derived produce about 10 bbl of crude. Heat derived from the steam is used to improve the displacement and recovery efficiency of the reservoir. The major benefit of heat is that the higher temperature reduces crude oil viscosity, allowing the oil to flow more freely into wellbores. Oryx operated about 934 thermal EOR wells located on seven leases (Fig. 2). Oryx divested these properties in late 1990.

A phenolic resin plugback technique was developed and successfully employed on thirty-two wellbores with open hole gravel packed completions in the Midway-Sunset field during 1987. This program resulted in a sustained water production decrease of 5,850 BWPD and an oil production increase of 256 BOPD. Total revenue and savings from the wellbore plugback project were estimated at $970,790 per year. The project paid out in 120 days. This paper will address the development, implementation, and results of this water control technique. This study demonstrates that control of water production is possible within an open hole gravel packed completion with the use of a phenolic resin. Successful placement of phenolic