Summary Yates field unit in Pecos County, Texas, has recently drilled its 100th short-radius horizontal drainhole. The program has been a technical and economic success for the field, providing efficient completions in this highly fractured reservoir. In the early stages of the program (1986 1990), short-radius drilling in Yates field unit was performed using strictly rotary drilling systems. In 1992, Odorisio and Curtis1 reported on the introduction of articulated downhole mud motors to the program and the impact of the initial modifications to the system. Since that time over 75 additional drainholes have been drilled. Two other drilling systems have been tested and many improvements have been made to the original system. This paper documents the optimization that has occurred in the drilling systems and the results obtained from this work. Introduction The Yates field unit is located at the southern tip of the Central Basin Platform, 90 miles south of Midland, Texas (Fig. 1). It consists of an asymmetric, horseshoe-shaped anticline with greater than 400 ft of closure that covers 26,400 acres.2 The main producing formation is the Permian age San Andres formation found at 1,200 to 1,700 ft. Being at a shelf edge, the formation was well worked from wave action depositing porous limestone grainstones. Tectonic events after deposition raised the field above sea level, causing fracturing and allowing solution enhancement (karsting) from fresh water.3 Subsequent burial led to nearly complete dolomitization, and the formation of an anhydrite seal from the Seven Rivers formation. The resulting reservoir today is a highly fractured dolomite with average matrix porosities of 18%, and initial well-productivity index measurements frequently exceeding 50 BOPD per psi of drawdown.2 Gravity drainage is the drive mechanism for the reservoir. A relatively thin oil column of 50 ft is bounded by an expanding gas cap and bottom aquifer. The density difference between the oil-filled matrix and the gas-filled portion of the fracture system above the gas/oil contact allows for a very efficient recovery mechanism. Since discovery in 1926, cumulative production has been in excess of 1.3 billion bbl, with current production averaging 54,300 BOPD. Since the introduction of the system in 1986, the objective of the short-radius horizontal program has been to enhance production in those areas of the field where localized areas of the reservoir are not as productive because of facies changes such as interbedded shales and secondary calcite cementation.1 Exposing more of the rock with a horizontal borehole minimizes gas coning and offers the opportunity to connect up with the major fracture trends in the field. Properly placed boreholes maximize the production efficiency in these areas of the field. The short radius system is the most cost-effective method of drilling horizontals in Yates field unit because it eliminates problems of drilling through a cavernous gas cap, can be used in the nearly 1,630 existing wells, and does not limit the lateral length necessary in this field with 10-acre spacing. General Discussion of the Short-Radius Technique The short-radius technique is almost exclusively used in existing vertical wellbores, and is typically drilled with workover rigs instead of drilling rigs. With less equipment being required to drill a short-radius well and most being re-entries, a large cost savings can be achieved over medium- and long-radius wells typically drilled as grassroots wells. This system builds a radius from vertical to horizontal in 20 to 100 ft and produces laterals ranging from 100 to 1,300 ft. If avoiding troublesome overlying zones are key to a successful well, short radius provides a method by which one can drill under these zones with casing isolation above. For example if a 45-ft radius is required to remain below difficult formations, and lateral lengths are limited to 1,000 ft due to well spacing, a short radius will provide nearly 50% more exposure to the zone of interest than a comparable medium radius well (Fig. 2). Even though some initial development of the system took place in the 1940's, short radius did not begin to be used until the 1980's.4 Initial short-radius horizontal wells were drilled using a rotary drilling system, in which drillpipe was articulated to negotiate the severe doglegs of the curve. Surveying was only possible after tripping for the steering tool. The flexible nature of the system, while allowing negotiation of very tight radii, also provided control problems. In the late 1980's downhole mud motors were developed that would negotiate the tight radii and allow continuous surveying with a downhole steering tool, or more recently measurement-while-drilling (MWD).5 For radii less than 70 ft, the mud motors were articulated in order to pass through the curve. The majority of short-radius horizontals are drilled in slide mode where the drill string is not rotated. For radii under 80 ft, rotation has to be limited to a rolling of the tool face, 3 to 5 revolutions every 5 to 10 ft.6 The limitation is the drillstring, not the motor systems. Above 80 ft, 20 to 30 rev/min rotation is possible with careful examination of drillstring integrity on a regular basis. Some work is being done with composite drillpipe, which is a combination of metal and fiberglass for added flexibility. Yates Field Unit Short-Radius Drilling Operations From 1986 through the end of 1995 a total of 105 short-radius horizontal boreholes have been drilled in the field (Fig. 3). This total includes 16 boreholes that were redrilled once gas/oil contact movement downward made the existing borehole unproductive because of excessive gas production. As previously discussed, the role of short-radius horizontal wells in Yates field unit is to maximize completion efficiency in those parts of the field where lower productivity exists by exposing additional reservoir and intersecting fractures. Minimizing gas coning is the ongoing production management objective of all wells in the field, and the short-radius horizontals have proven the most effective method to combat this problem where traditional vertical completions are insufficient.
Yates Field Unit in Pecos County, Texas, has recently drilled its 100th short radius horizontal drainhole. The program has been a technical as well as economic success for the field, providing efficient completions in this highly fractured reservoir. In the early stages of the program (1986 - 1990), short radius drilling in Yates Field Unit was performed using strictly rotary drilling systems. In 1992, Odorisio and Curtis reported on the introduction of articulated downhole mud motors to the program and the impact of the initial modifications to the system. Since that time over 75 additional drainholes have been drilled. Two other drilling systems have been tested and many improvements have been made to the original system. This paper documents the optimization that has occurred in the drilling systems and results obtained from this work.
Horizontal well targeting has been a greater challenge in massive fractured carbonates than in low productivity, poorly connected, relatively thin reservoirs. Targets in three dimensional space have been specified to both confirm the fracture interpretation and establish high efficiency oil capture. Several well examples are presented to illustrate the targeting objectives and the resulting well performance. Early horizontal drilling objectives often pushed the operator to drill as far as possible in a selected optimum direction, using the same philosophy as is used in matrix dominated reservoirs. Results presented indicate profit maximization by drilling to a specific target to intersect a fracture trend at an optimum elevation instead of concentrating on maximizing length of lateral. Intervals of rapid penetration, lost circulation, and/or bit slides, along with cutting sample compositions, provided insight for confirmation and extension of the fracture network interpretation. The width of disturbance and degree of fracturing along pre-drill interpreted highly flexed trends is valuable data for improved fracture network interpretation and computer simulation. Both the elevation and number of fracture branches encountered are significant strategic planning issues for oil recovery from unconfined oil columns in a massive carbonate system. Results from a large number of horizontals indicate the productivity increases achieved by proper targeting of laterals into major fracture features. Proper targeting of horizontal wells in fractured carbonates can maximize profit while minimizing environmental impact by limiting the total number of reservoir completions necessary to effectively develop the field. Introduction Horizontal wells provide a unique assessment tool for formations containing reservoirs dominated by discontinuous flow features. Massive carbonate formations are the most extreme setting for large-scale high contrast discontinuous reservoir properties. In sandstones of moderate to low quality, horizontals are typically applied to improve rate by exposing additional formation for fluid entry at high drawdown. In carbonates, horizontals serve to intersect high conductivity features. In sandstones high flow quality often coincides with high hydrocarbon storage. In contrast, carbonate flow parameters are often highly discontinuous while their storage capacity remains a relatively continuous function (as limited by depositional and diagenetic porosity history). Since 1993, quite a bit of study has gone into identifying the extent and quality of fracture networks and the impact these systems have had on reservoir management, fluid re-injection, and completion efficiency. In West Texas alone, well over 100 short radius horizontal wells have been drilled in one field since 1986. Horizontals drilled in this fractured carbonate were initially done to maximize oil production while limiting gas coning. With the recent fracture studies, emphasis has moved to using horizontal boreholes to connect large flow features from existing wellbores not currently connected. These more recent wells have targeted fracture zones interpreted from flexure maps which are developed from a second derivative analysis of structural surface maps. This paper examines several of the horizontal wells drilled with the intent of cutting the interpreted fracture zones to provide connection to the large flow features of the carbonate reservoir. Targeting horizontal wells involves a discussion of massive carbonate features as well as discontinuous features. This paper will also discuss how mapping was used to determine flow feature locations. The horizontal drilling techniques used to intersect these targeted flow features will be outlined along with the assessment of flow features while drilling. A discussion of the refinement of the interpretation and the drilling operations involved will follow. Massive Carbonate Flow Features What is a massive carbonate? P. 601^
Traditionally, operators have had limited options for conducting remedial work on lateral re-entries through milled-casing windows. This limitation is due to the necessity of using a "bent joint" of pipe to guide tools through the window. If a bent joint of pipe cannot be attached to the end of the assembly (e.g. a drilling assembly), a whipstock is required to deflect the assembly out the window. Setting a conventional whipstock requires the use of orienting tools that add significantly to the wellcost. This paper describes the world's first applications of unique technology that helps solve these problems by facilitating the exiting of milled-casing windows with service tool assemblies during remedial operations. The system uses the patent-pending "self-locating" lateral re-entry technology as an integral component of the Lateral Re-entry Whipstock to assure the proper orientation and elevation of the whipstock tool face with the casing exit window. The technology described in this paper has bearing on TAML Level II1 junction re-entry operations for clean out, production enhancement, increased reservoir drainage, zonal isolation, and re-completion of lateral wellbores in multilateral completions. Introduction The Permian Basin is an area where re-entry style horizontal drilling from existing wellbores has been used extensively. Drilling horizontal laterals from existing wells is more economical than drilling new wells because the costs of drilling and running casing down to the producing formation is eliminated. Due to reservoir pressure depletion, many re-entry horizontals require the use of artificial lift. In order to maximize drawdown in a pressure-depleted reservoir, the downhole pump should be set below the lateral's window. Consequently, the whipstock used to mill the casing window and drill the horizontal lateral wellbore must be pulled before installing the pump. The Challenge. Any remedial work to be conducted inside these re-entry horizontals can be a challenge because the drilling whipstock is not in the well to guide the workover string out through the casing window. Therefore, other means of guiding the string out the window must be devised. The most commonly used method locates the window with a "bent sub" on the end of a workstring. While this is often sufficient, the "bent sub" limits the assemblies that can be passed through the window. Some assemblies (e.g. drilling) are too stiff or large to be deflected over to and out a casing window even with the aid of a bent sub. The operator of the North Indian Basin Unit wanted to sidetrack an open-hole horizontal lateral in order to reach an untapped area in the reservoir. This objective meant that they were faced with the challenge of passing a 4–3/4-in. directional drilling assembly through a 7-inch casing window.
Horizontal well targeting is often a greater challenge in massive, fractured carbonates than in low-productivity, poorly connected, and relatively thin reservoirs. This paper discusses methods to target horizontal wellbores in three-dimensional space to both confirm the fracture interpretation and establish high-efficiency oil capture. Several well examples are presented to illustrate the targeting objectives and the resulting well performance. Early in the program, the horizontal drilling objectives sought to maximize the lateral length in a direction determined by offset well productivity; the sample philosophy as is used in matrix-dominated reservoirs. Analysis of these results and employment of methods presented in this paper indicate profit can be maximized by drilling to a specific target to intersect a fracture trend at an optimum elevation instead of concentrating on maximizing length of lateral. Intervals of rapid penetration, lost circulation, and/or bit slides, along with cutting sample compositions, provided insight for confirmation and extension of the fracture network interpretation. The width of disturbance and degree of fracturing observed along interpreted fracture trends are valuable data for improved fracture network interpretation and computer simulation. Both the elevation and number of fracture branches encountered are significant strategic planning issues for oil recovery from unconfined oil columns in a massive carbonate system. Results from a large number of horizontals indicate significant productivity increases are achieved by proper targeting of laterals into major fracture features.
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