Converting Wells in a Mature West Texas Field for CO2 Injection
- M.T. Power (Chevron U.S.A. Inc.) | M.A. Leicht (Chevron U.S.A. Inc.) | K.L. Barnett (Chevron U.S.A. Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling Engineering
- Publication Date
- December 1990
- Document Type
- Journal Paper
- 306 - 310
- 1990. Society of Petroleum Engineers
- 4.3.4 Scale, 5.7.5 Economic Evaluations, 3 Production and Well Operations, 7.3.3 Project Management, 5.4.2 Gas Injection Methods, 2 Well Completion, 1.6.1 Drilling Operation Management, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.2 Separation and Treating, 2.2.2 Perforating, 1.6 Drilling Operations, 6.5.2 Water use, produced water discharge and disposal, 4.2.3 Materials and Corrosion, 1.10 Drilling Equipment, 4.1.5 Processing Equipment, 1.14.3 Cement Formulation (Chemistry, Properties), 1.11 Drilling Fluids and Materials, 1.6.9 Coring, Fishing, 5.4 Enhanced Recovery, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 1.14 Casing and Cementing, 1.2.3 Rock properties, 5.4.1 Waterflooding
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Summary. This paper deals with the planning, special equipment considerations, and operations necessary to convert 165 water injection wells to CO2 injectors that will function through at least the end of the century. The paper is divided into two parts: planning and engineering (wellhead, packer, and tubular selection) and procedural operation highlights (fishing, openhole cleanout, casing evaluation and repair, stimulation, liner running, wellhead replacement, packer setting, and the reworking of tubulars). A case-history approach was used to analyze the success or failure of the various methods and techniques used in this project. All 165 wells were converted as of March 29, 1989. project. All 165 wells were converted as of March 29, 1989. Introduction
Chevron U.S.A.'s North Ward Estes (NWE) field is an 18 x4-mile anticlinorium located in Ward and Winkler Counties; TX. The field is roughly 60 miles southwest of Midland and lies on the western flank of the Central basin platform.
The Yates is the dominant producing formation. It is composed of up to nine major reservoirs. The individual reservoirs are very-fine-grained sandstones to siltstones separated by very dense dolomite beds. The average depth of the Yates is 2,800 ft.
The NWE field was discovered in 1929 and to date has yielded more than 330 million bbl of oil (30% of original oil in place). Current production averages 2,849 BOPD in the project area.
Many older areas of the NWE field began to approach their economic limit in 1954. A pilot waterflood was initiated on the Hutchings Stock Assn. lease in late 1954. Expansion to cover the entire field began in mid-1955; by 1965, 26,000 acres was under waterflood.
Since 1975, a number of tertiary pilot projects have been conducted in the NWE field. These include in-situ combustion, caustic flooding, and polymer-injection-profile modification.
In 1985, an economic evaluation of the project area was made to investigate the current viability of a CO2 flood. On the basis of positive results of the CO2-flood investigation, a task force was established to develop the procedures for converting the wells to CO2 injection. The task force was led by a project manager. Reporting directly to the project manager were a petroleum engineering group, a facilities engineering group, a project accountant, and a field operations group. Assigned to work with the task force but reporting to their respective functional managers were a drilling superintendent, drilling engineer, four drilling representatives, and two geologists.
The project incorporated six sections of the field. The project uses existing waterflood injection and production wells on 10-acre spacing. The average age of the wells is about 35 years, with some wells older than 55 years. In total, 96 of the 165 injection wells (58%) are completed in open hole. All have at least one liner; many have two or more.
Procedural Operations Procedural Operations The objective of the conversion work was to prepare 165 wells for CO2 injection. This was accomplished by removing existing fiberglass and steel liners, cleaning the wellbore to an acceptable depth, treating the wellbore with various chemicals and acid to clean near-wellbore damage, running new liners, changing existing threaded wellheads with flanged equipment, and running new injection packers on 2 3/8-in. IPC tubing that is either new or reconditioned or has packers on 2 3/8-in. IPC tubing that is either new or reconditioned or has a fiberglass inner liner.
Four types of wells were converted during the project: Type 1-nitro-shot openhole injectors (60 wells); Type 2-openhole injectors (36 wells); Type 3-cased-hole injectors with plugback requirements for zonal isolation (15 wells); and Type 4-cased-hole injectors with no plugback requirements (54 wells). Even though only four types of wells existed, each of the 165 wells was unique m its own way. `Cookbook" procedures were prepared at the beginning of the conversion work to give the drilling group a direction and objective for each well. As the work progressed, however, casing leaks were found and repaired, junk in the hole required sidetracking, and sloughing shot holes required mudding up to complete the conversion. Thus, changes in our operations from the original procedures evolved owing to monetary constraints and rethinking of what techniques were actually successful.
Casing Evaluation and Repair
Elimination of casing inspection logs is an example of both reasons for changes in operations. Evaluation of logs from more than 20 wells revealed that essentially all the wellbores were in the same condition: reasonably good casing down to the old injection packer and no casing below the packer. Also, the logs failed to locate packer and no casing below the packer. Also, the logs failed to locate explicitly holes in the casing (above the injection packer) where subsequent packer and retrievable-bridge-plug testing found leaks. Casing inspection logs were then deleted on most wells except where casing leaks had been detected on previous workovers. This application was an attempt to determine whether casing corrosion necessitated casing replacement (running a liner or full string). Another continued application of casing inspection logs was on Type 3 wells, where' a setting depth for a cast-iron bridge plug or cement retainer was to be determined to ensure zonal isolation on a plugback. A full string of casing or a liner was needed on five wells. These wells had numerous casing leaks that could not be squeezed and tested to 500 psi for the Texas Railroad Commission's (TRC's) H-5 test.
Casing repair by cement squeezing played a large role in this project. Many of these wells, drilled years ago, did not have cement project. Many of these wells, drilled years ago, did not have cement circulated to surface on the production casing strings, which left long intervals exposed to highly corrosive water flows from the Rustler formation. Cement squeezing was necessary on 31 wells, requiring 196.5 days of rig time, including time to isolate and squeeze the leak(s), wait-on-cement time, time to drill out cement, and time to H-5 test the leak(s). Slurry selection depended on the depth, the. interval length of repair, and the injection rate. Many injection rates were relatively high volume and low pressure: 3 to 6 bbl/min with 200-to-500-psi pump pressure. For these types of leaks, a two-slurry method was used. A lead slurry of 150 to 250 sacks of Class C+0.25 lbm/sack Flocele +5 lbm/sack Gilsonite mixed at 14.8 lbm/gal was initially pumped. The tail slurry consisted of 100 to 150 sacks of Class C+fluid-loss additive+friction reducer+calcium chloride mixed at 14.8 Ibm/gal. The design parameters of the tall slurry were a fluid-loss value of 50 to 100 cm for a 30-minute test and a pump time of 2 to 2 1/2 hours. All low-water-loss slurries were tested according to API Spec. 10 (Alternate Schedules 12 and 13). All cement squeezes were designed to be implemented by the hesitation-squeeze method. The intention of this two-slurry method was for the first slurry to begin bridging across the formation face as it was injected through the hole in the casing. The tail slurry would then be squeezed against the bridges formed by the lead slurry.
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