This paper presents two field case histories from multiyear horizontal completion projects in west Texas that were very successful at exposing the "false economy" of not cementing casing in horizontal wells drilled in low-permeability reservoirs. Moderate increases of 20 to 25% in initial well costs yielded a 3- to 10-fold increase in discounted cash flow through improved hydrocarbon recoveries. Case histories are developed for adjoining wells with similar reservoir characteristics and differing completion techniques. Comparisons of single lateral cemented liner completions to openhole completions and uncemented liner completions will also be presented.

Problems related to paraffin and asphaitenes continue to plague the oil and gas Industry. These include solid deposits, stabilization of emulsions and sludge production"'. Common solvents and condensates are popular treatments for dissolving and/or controlling paraffin and asphaltene related problems. Typically, these fluids have been used with little regard for long term effectiveness and formation damage consequences. Unique condensate feedstocks with high multiple aromatic content were identified. Laboratory testing, blending and refining resulted in solvents that can keep paraffin and asphaitenes in solution under a wide range of conditions. As a result of this work condensates are blended and refined to maximize solvency, demulsifying properties and maintain wettability without the addition of chemical additives. The properties of these refined natural solvents offer economical alternatives and/or enhancement to common treatment practices including hot oiling, condensate treatments, chemical treatments, stimulation and production treatments.

The Unit Operating Agreement is the contract among unit working interest owners which controls their respective functions in unitized operations. While the provisions of the operating agreement related to field wide units are generally acceptable to non-operators, there are, however, some areas of concern. The purpose of this paper is to briefly discuss some of those problem provisions.

Recognizing and cost effectively eliminating liquid loading in natural gas wells through the use of low pressure wellhead compression. The use of compression to eliminate liquid loading can be utilized in conjunction with other production methods such as soaping, siphon strings, plunger lift and beam pumping. Desireable features of low pressure natural gas compression will be highlighted with actual field cases illustrating the equipment characteristics needed for successful de-liquification of natural gas wells. Through computer analysis of pressure and area flow rate analysis, along with field testing and continued montitoring, the changing of compressor clearances, in conjunction with control valves, can be optimized to successfully keep gas wells unloaded during a longer period of time without resizing and replacing the compressor. Thus far the proper sizing and utilization of low pressure wellhead compression has enabled operators to maintain higher producing rates and velocities to keep gas wells unloaded which increases the monthly cash flow to the producer and extends the economic life of properties which leads to the recovery of increased incremental reserves.

The Variable Slippage Pump

More and more interest is generated for fiberglass tubulars because of their excellent corrosion resistance and mechanical strength. The major obstacle for more extensive use of fiberglass has been the lack of recognized engineering standards that would allow the field engineer to specify fiberglass with confidence for a particular application. Recognizing this need, several API committees are at work with unusual speed and efficiency to develop product specifications for fiberglass tubulars. Specifications for low-pressure line pipe were issued in 1986. Specifications for high-pressure line pipe followed in 1988. A specification for fiberglass downhole tubing is expected to be issued next year, in 1991. Finally, a specification for fiberglass casing is planned to be issued in 1992. This paper summarizes these API activities and details API fiberglass product specifications, both those issued and those still in committee.

More and more interest is generated for fiberglass tubulars because of their excellent corrosion resistance and mechanical strength. The major obstacle for more extensive use of fiberglass has been the lack of recognized engineering standards that would allow the field engineer to specify fiberglass with confidence for a particular application. Recognizing this need, several API committees are at work with unusual speed and efficiency to develop product specifications for fiberglass tubulars. Specifications for low pressure line pipe were issued in 1986. Specifications for high pressure line pipe followed in 1988. A specification for fiberglass downhole tubing is expected to be issued next year, in 1990. Finally, a specification for fiberglass casing is planned to be issued in 1991. This paper summarizes these API activities and details API fiberglass product specifications, both those issued and those still in committee.

ARC0 Oil and Gas Company has completed six drainhole wells in the Empire Abo Unit and plans to complete four more in early 1984. A drainhole well is one in which the wellbore has been deviated from vertical to horizontal with a turn radius of 20 to 30 ft. The horizontal hole extends up to 200 ft. Figure 1 illustrates an ideal drainhole completion. The increased surface area open to flow in the oil column reduces the susceptibility to gas coning as compared to conventionally completed wells. "Conventional Well" refers to a cased, vertical wellbore which has been perforated and acidized, (Fig. 2). A density-controlled acid job is generally used when stimulating to prevent etching upward to the gas cap. Even with the density-controlled method, significant upward etching occurs, increasing the susceptibility to gas coning. Initially, new wellbores were drilled for the drainhole completions. Recently a technique was devised and tested in the field to complete existing cased wellbores as drainhole wells. The main advantage of this new procedure is a substantial saving in drilling and completion costs. This paper summarizes the observed performance of the drainhole wells. A basic outline of the procedures used to drill the first six drainhole wells is included.

ARCO Oil and Gas Company started producing the nation's first large-scale natural carbon dioxide (C02) reservoir on January 31, 1983, from the Sheep Mountain Unit located in Huerfano County, Colorado. With the installation of a 330 MMCFD capacity pipeline, completed in January 1983, this CO2 has become an important source for future enhanced recovery projects in the West Texas area. This paper describes the Sheep Mountain reservoir, including a geological history, and the current theories for CO2 creation and migration in the Dakota and Entrada formations. A comparison of CO2 fluid properties to hydrocarbon fluid properties is presented, followed by a discussion of the producing characteristics of the wells and the conditioning processes employed before the CO2 is placed in the pipeline. An account of the problems encountered since start up and the resulting or proposed solutions is also included.

The purpose of this paper is to present an objective non-technical discussion, describing and comparing surface and downhole analysis. Previous discussions of surface and downhole analysis have been offered with only casual reference to each other. Both surface and downhole analysis can play an important role in practical well analysis programs.

A Pressure Vessel Management System (PVMS) using a computer program called PVCALC has been used extensively by Conoco's Midland Division for the last two years. PVMS was originally implemented (intra-Division) to be sure that all new pressure vessels bought for the Midland Division met the ASME Code. The program has been expanded to analyze surplus equipment. Vendor designs on at least 17 new pressure vessels have been analyzed, with only 12% of the vessels meeting ASME Code on first analysis. Ten surplus pressure vessels have been analyzed with PVMS and used, saving $500,000. The paper will cover the different problems that were found and actions taken to ensure that all pressure vessels meet ASME Code.

Recent field tests in South Louisiana have culminated a three-year research project by Baroid. The project objective was to apply the computer expertise developed while producing Baroid's CDC (Computerized Drilling Control) units introduced in 19711 to the development of an automatic pore pressure logging system. The CDC units require crews of up to seven people. The proposed system was to require only three crew members through more reliance on the computer for data collection, analysis, and presentation. The system (now designated Automatic Logging Service - ALS) evolved through several distinctive developmental phases. The first was the theoretical phase in which a mathematical model of the drilling operation was developed. This phase was reported by Bourgoyne and Young in 1973.2 The second phase consisted of field-testing the model through use of electronic calculators at the well site. The third phase was to implement the model in software for a mini-computer designed for real-time operation. The fourth and recently completed phase was to field-test the complete equipment and software package system. The ALS unit is designed to use a modern digital mini-computer, sensor devices, a system of mathematical equations, and one operator per tour to produce a pore pressure log on a continuous basis while drilling. Computer system responsibilities include data monitoring, storage, analysis, and presentation. Data collection is accomplished through the use of rig-mounted transducers that monitor the drilling parameters and transmit analog signals to conditioning panels. These panels then convert the transducer outputs into computer compatible signals. The computer reads and scales these values into engineering units. Parameters being automatically monitored are depth, hook load/bit weight, rotary speed, pump strokes per minute, on/off bottom, catalytic mud gas, and thermal mud gas. Parameters manually entered into the computer are mud density, shale density, sand/shale percent, and pertinent wellbore constants. Drilling data storage is accomplished through the use of a magnetic cassette tape unit that is fed from the computer on a time and event basis. Events that cause tape records to be generated are: the beginning of a bit run, the end of a bit run, the completion of a drilling interval, and the completion of a lag interval. During drilling, data averages are accumulated until an interval is completed. These averages are then stored on the tape. Records are created of certain data lag arrays on a time basis to minimize loss due to power failure. These lag arrays are dumped onto tape every 15 minutes. The system recovery program, following a power outage, automatically reads the most current lag array record into memory. The format of the stored data permits easy on-site utilization. Data analysis is done by applying the drilling model and drilling response equations. Drill rate is computed from the depth and on-bottom signals for several interval sizes (1, 2, 5, and 10 feet)

Paraffin problems can now be controlled economically by the use of a chemical dispersant. This paper reports on the progress made thus far with the use of a new chemical dispersant, available in four forms for field application ease; the location of certain major problem areas; and the various geographical locations where these new dispersants have been effectively used. Realizing one of the problems for making products of this nature work is precise field application; this paper also presents a scientific method for determining the treating requirements for two of the forms.

As the production of oil increased, the emulsion problem increased. The companies, realizing that some better way of separating the water and oil had to be devised, installed large tanks, both wooden and steel, placing steam coils inside them. This method proved superior to the old pit system, however, it was far from perfect. Not only did the emulsion that was not treated create a disposal problem, but much of it was impossible to break down with the heat alone, consequently other methods were sought. Thus the first commercial treating chemical was used.

Paraffin is costing the crude oil producers untold millions of dollars per year. In down time, loss of production, plugged wells, lines and emulsified oil in storage tanks. This problem has been attacked in many ways and until a few years ago, the removal of such deposits was done by mechanical methods, oil producers sought the use of chemicals such as solvent and paraffin inhibitors, of which there are several chemical formulas on the market that are doing the job economically and well, if they are properly applied.

Thirty-two gas wells were incorporated into a computer program in the Greta Field, Refugio County, Texas. This computer program includes gas measurement for all 32 wells and control of 15 wells. Individual computers for each well are located at the lease metering sites. Flow volumes are recorded, and wells are controlled from a console located at the Tom O"Connor Gas Plant. Transmission of signals between computer and console is through an aerial multiconductor cable. The use of computers has eliminated the need for 24 hour pumping service to regulate volumes and the need for the orifice recording charts.

This paper contains a discussion of the design and operation of the electric immersion heating element as well as the results and interpretation of the field test that was conducted.

This paper describes the use and results of using expanding cement to repair casing leaks in West Central Texas. In the past, casing leaks were squeezed using Class C cement (high sulfate resistant. This would take from three to five hours and often several stages, The use of expanding cement has cut the time required for squeezing to one-half to two hours, usually requiring only one stage. This method uses the high gel-strength cement to hold its own hydrostatic pressure to give a quick shut-off to casing leaks. The weight of this cement is heavier than ordinary Class C cement.

The ever-increasing shortage and resulting higher prices of natural gas and oil make it important to conserve fuel whenever possible. One way is to remove all free water from the produced oil Stream before treating the emulsion. This paper discusses the application, design installation, operation, maintenance, trouble shooting, and corrosion protection of free-water knockouts used for this purpose.

Factors to he considered in the selection of inhibitors and treating techniques used to control downhole corrosion in gas wells are discussed with special attention to deep, hot wells. Corrosion monitoring is recognized as a complex but necessary part of any corrosion control program.

Corrosion of oil field production equipment is a serious problem which is many times not given the consideration it deserves. Every year, the oil industry pays a corrosion bill running into millions of dollars. In many cases, the fact that some of their sots can be eliminated is not realized, and others, the ravages of corrosion are not recognized. It is now possible in some cases to economically allay the reoccurring costs of maintenance of equipment, and in others to percent the actual destruction of the equipment. Several methods of providing corrosion protection have proved satisfactory for use in oil field equipment. Each one has its special uses. No one plan or method is the most economical for all conditions. One of the most important and most widely used is protective coatings. Use of these materials goes back to the early 1940"s. Where the proper coating is properly applied, protective coatings have given excellent results.

A new analytical procedure is described here for predicting well performance and analyzing completion effectiveness of wells which have a significant pressure drop from turbulence. (In this discussion we use the term turbulence to describe both turbulence and all other rate dependent deviations from darcy flow such as inertial effects.) The procedure is more applicable to gas well completions but has been applied to a high-rate oil well. In particular, the new procedure should provide a powerful analytical tool in areas where most wells have high production potential. The procedure can be used in wells requiring sand control measures and in hydraulically fractured wells to determine if the cross-sectional area open to flow into the wellbore is sufficient. It also provides an indication of perforation effectiveness in normally completed wells because an abnormally high turbulence coefficient indicates too few open perforations. Incidental to determination of a turbulence coefficient, the new procedure provides a laminar flow coefficient which includes skin effect. If permeability thickness is known, an estimate of skin effect can be made from the laminar flow coefficient. Also included in the theory is an explanation of the effects of partial completion or a change in completion geometry on pressure buildup results when the turbulence pressure drop is significant. The analysis procedure permits determination of turbulence effects on completion efficiency irrespective of skin effect and laminar (darcy) flow. The required data are either: (1) two or more stabilized flow tests; or (2) two or more isochronal flow tests. Flow rates and bottomhole flowing pressures must be known in either case. Transient pressure data are not needed and bottomhole flowing pressures calculated from surface pressures may often be sufficient. The previous means of determining the turbulence coefficient have required some means of obtaining kh; usually a buildup test coupled with several production tests or a series of buildup tests. These were used to determine a total skin effect, s", which included the turbulence term. The s" values were then plotted versus flow rates. Actual skin effect and turbulence coefficients were then calculated from the intercept and slope. The new method avoids the necessity for transient data from a buildup or drawdown test and permits a direct plot of pressure data versus rate. The added simplicity should make the new procedure much more useful in direct field applications.

Proper use of d-exponent data accurately predicts formation pressures while drilling in the Delaware Basin. This paper shows how this information can be used to minimize drilling costs by: 1) Proper maintenance of well control. 2) Selection of casing seats. 3) Prediction of hole stability caused by heaving shales in an underbalanced system.

Test data collected from the TTU test well plus field data will be used to show the impact of pump clearance and pumping speed on pump slippage. Pump slippage significantly increases with increased well depth due to high temperature reducing water viscosity and increased differential pressure acting across the plunger. Specifying plunger length and other recommended practices will be discussed. A procedure to design the pump clearances based on sensitivity of the various correlating parameters will be presented. The Patterson Pump Slippage equation is discussed and a totally theoretically equation is shown to give similar slippage results which only adds to the credibility of the method. Pump efficiency can dramatically decreases at slow pumping speed when pump clearances are large. Additional energy must be input to the sucker rod pumping system to re-pump the portion of the pump's displacement lost to slippage. Even with the equations and guidelines available, the operator frequently uses too large of pump clearances for the well conditions and the reason for the low resulting production rate can be difficult to identify. Use of open or tight pump clearances should be based on well conditions. For large clearance pumps the efficiency decreases as the pumping speed is decreases plus the efficiency decreases when pumping from deeper depths.

This paper serves to up-date applications and results of the Vannsystem. The Vannsystem is the process of running large casing guns on tubing for maximum completion performance. Prior papers on this system have dealt primarily with maximum differential perforating to overcome formation damage. The 3,000 plus wells completed using this technique included such applications as tight gas sands, highly unconsolidated sands, intervals of several hundred feet, formation evaluation, off-shore, injection wells, and others. Recent key applications, along with case histories, will be reviewed. The use of tubulars makes it possible to customize completions under such a variety of conditions.