Abstract Hydraulic fracturing in the secondary recovery units in the Permian Basin of west Texas is often complicated by a number of factors. Generally, there exists a lack of historical data or information required to effectively design the desired treatment. Therefore, treatments in these fields have often been "cook-booked" and given less engineering attention due to their smaller size and scope. Many times the process is further complicated by the iterative nature required in effective treatment modeling (i.e., historical review, candidate selection, pre-job design, pre-job diagnostics, on-site or post-job modeling, and post-job diagnostics). In this paper, we will outline the steps required to improve these processes without expending excessive resources. Then, we will discuss steps where streamlining the process is warranted without compromising the end result, Finally, we will document and present several cases illustrating effective use of these technologies to obtain more accurate stress profiles and improved fracture treatments in secondary, in-fill development projects. P. 281

Abstract 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.

Summary The quality of injection waters used in any new or existing waterflood or EOR process should be considered as a critical component of reservoir management and surveillance programs. Despite decades of industry experience with recovery processes utilizing water in the Permian Basin (and most other major oil producing basins of the world), water quality is an often neglected aspect of reservoir management programs. Consequently, severe injectivity and operational problems are frequently experienced. This paper describes a case study of water quality control for the Clearfork and Glorieta reservoirs (Permian age) of the North Robertson Unit (NRU) located in the Permian Basin of West Texas. A cost-effective surveillance program for the timely identification and treatment of potential water quality control problems has been designed and implemented. Integration of geological and reservoir parameters, which are crucial to ensure the realization of optimal reservoir performance and operational objectives, is highlighted. Introduction To North Robertson Unit Location, Well Types: NRU is located in Gaines County, Texas in the northern part of the Central Basin Platform of the Permian Basin. The target reservoirs are the Glorieta and Clearfork Formations (herein referred to as the Lower and Upper Clearfork). The hydrocarbon bearing interval extends from the top of the Glorieta to the base of the Lower Clearfork, between the correlative depths of approximately 5,870 – 7,440 feet. The NRU project area of 5,633 acres has a total of 259 wells as of January, 1994 (FIGURE 1). This includes 144 active producing wells, 109 active injection wells and 6 water supply wells. Development and Production History: Production from the North Robertson field area began in 1956 with 40-acre primary depletion development. This 40-acre primary development resulted in 141 producing wells. The NRU was formed effective March, 1987, for the purpose of implementing waterflood operations and infill drilling from 40-acre to 20-acre well spacings. At the time of unitization, the oil production from the Unit area was approximately 670 BOPD with a GOR of about 1,550 SCF/STBO and water production of about 500 BWPD. No secondary recovery operations were initiated until unitization and subsequent to infill drilling. Most of the 20-acre infill drilling was conducted from unitization to the end of 1991. The current waterflood utilizes a 40-acre 5-spot pattern type with 20-acre nominal well spacing. Currently, the NRU produces approximately 3,250 BOPD, 1,400 MCFPD, and 10,600 BWPD. Current water injection volumes are approximately 23,000 BWIPD, with injection water comprised of both produced water and fresh water from the Ogallala aquifer obtained from source water supply wells within the Unit. P. 419^

Abstract New source air permitting of Oil and gas processing equipment ranges from fairly simple procedures under the Texas Natural Resource Conservation Commission (TNRCC) standard exemption list and the New Mexico Environment Department (NMED) registration regulations to an extremely complicated procedure requiring a federal Prevention of Significant Deterioration (PSD) and/or non-attainment review. The following topics relating to obtaining air pollution construction permits for processing equipment will be addressed in this paper: – Type of permit/exemption/registration necessary for construction – Specific permit/exemption/registration requirements – New Source Performance Standards (NSPS) Subparts KKK, LLL, GG, K, Ka, and Kb Concepts outlined in this paper pertain to air pollution New Source Review (NSR). Owners and operators of Oil and gas processing and production facilities that propose new or modified facilities should be aware of the regulations and interpretations contained in this paper. The primary effects of the 1990 clean Air Act amendmentson NSR requirements are identified. Type of Permit/Exemption Necessary for Construction Before equipment can be installed in Texas, the requirements of the TNRCC standard exemption list must be met, or state and/or federal permitting review is required. The installation of a compressor engine, turbine, sweetening unit (with associated sulfur recovery unit or flare), or a heater/boiler will require one of the following: – TNRCC standard exemption – State (TNRCC) construction permit (Regulation VI) – State (TNRCC) construction permit and federal (PSD) permit – State (TNRCC) construction permit and federal non-attainment review – State (TNRCC) construction permit, federal (PSD) permit, and federal non-attainment review P. 649^

Abstract The modification of the Cullender and Smith equation presented here consists primarily of adding a gas-water ratio term, and a friction factor term as given by the explicit Jain-Swamee correlation. The results of this study show a reduction in the average error in predicting bottom-hole pressure of 3.4 percent for the flowing cases and 1.9 percent for the static case when the modified Cullender and Smith equation was used instead of the original Cullender and Smith equation. This study resulted in two major conclusions. First, modification of the Cullender and Smith equation produces a more accurate method of calculating static and flowing bottom-hole pressures. Second, using an apparent roughness of 0.0023 inches instead of an absolute roughness of 0.0006 inches will further reduce the RMS error for the flowing case. Introduction In order to estimate the absolute open flow potential of a gas well, it is necessary to determine the static and flowing bottom-hole pressures. This is done either by actual measurement with a bottom-hole pressure gauge, or by calculation using wellhead pressure measurements. This paper is only concerned with the calculation of bottom-hole pressure from wellhead measurements. Currently, the Texas Railroad Commission recommends calculating bottom-hole pressure by the average temperature and compressibility method. However, as the name implies, this method assumes a constant gas compressibility factor determined from an assumed average temperature and pressure for the entire flow column. Although these assumptions are fairly accurate in shallow wells, this procedure results in more error as depth. temperature, and pressure increase. Aziz concluded that a more practical approach is that of Cullender and Smith, which treats the gas compressibility factor as a function of depth. However, the Cullender and Smith method was developed for dry gas wells in rough-turbulent flow with a absolute roughness of 0.0006 inches. Peffer, Miller, and Hill used a variation of the Cullender and Smith method to calculate bottom-hole pressure. They modified the gas gravity correlation to take into account condensate and/or water production, and used the Nikuradse friction factor correlation for rough-turbulent flow. The purpose of this study is to modify the Cullender and Smith equation to account for water production and employ a friction factor correlation to take into account smooth-turbulent and rough-turbulent flow at any absolute roughness. The data on 78 wells obtained from the Peffer, Miller, and Hills' paper is reported in Table 1. Unfortunately, information on hydrogen sulfide, carbon-dioxide, and nitrogen concentrations were not provided for wells 29 through 78. Determination of the Modified Cullender and Smith Flowing Bottom-Hole Pressure Equation The modification of the Cullender and Smith equation to take into account condensate and/or water production stems from the fundamental mechanical energy equation. This energy balance can be expressed for steady-state flow as shown in Eq. 1. (1) P. 311^

This paper was prepared for the Permian Basin Oil Recovery Conference of the Society of Petroleum Engineers of AIME, to be held in Midland, Tex., March 11–12, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication is the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication is the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Attempts to stimulate marginal gas producers in Sutton County, Texas, has provided an producers in Sutton County, Texas, has provided an opportunity to evaluate several types of stimulation fluids on a comparative basis. The fluids used here included water base, oil base, and acid base fluids. A thorough study of the production history of wells following treatment production history of wells following treatment demonstrates the effectiveness of the different fluids on a long term basis. Conclusions drawn from this study provide a guide to selection of fracture fluids for tight gas sands. Cost-performance factors are explored as they apply to stimulation of marginal gas production and further conclusions are drawn production and further conclusions are drawn concerning the importance of formation damage as a function of formation petrophysical properties. Examples are shown to indicate formation damage is a factor to consider in fracturing tight sands but performance compromises may be made in the choice of fluid to obtain maximum frac penetration. penetration Introduction Shortages of many chemicals used in well stimulation treatments has led to re-evaluation of many gas well treating techniques. Nowhere has this been more the case than in the Canyon play of Sutton County, Texas. A previous paper play of Sutton County, Texas. A previous paper (SPE 4678) describes the treating methods used in the initial development of the Sawyer Field. This study has been continued and cost effective fracturing has resulted. The results of the fracturing development may serve as a model for gas well stimulation in other areas with production from similar zones. production from similar zones. FORMATION The Canyon, a Pennsylvanian Age sand, is generally found at approximately 6500 feet and is produced to about 8200 feet. The zone is massive with many "ratty" sections. These sections are low in permeability (1 md) and porosity (8–12 per cent). When contacted by fresh water there is a noticeable clay migration. Acid response tests indicate migration damage accounts for about 35–40 per cent loss in permeability. Formation liquid saturation is low and any liquid entering the formation may cause further loss in relative permeability. Gas-oil ratios indicate an essentially dry gas formation.