CO2 floods impose a number of artificial lift challenges to an operator. Typically as a flood matures, a significant number of the producers are affected by the (X&-water injection cycle. Producers swing through a broad range of producing characteristics. It is not unusual, depending on the injection cycle, for a producer to load up during the water cycle and then flow strongly during the CO2 injection cycle. These wide swings cause troublesome failures, a loss in production and lead to higher operating cost. Since late1995,Alhna Energy has been testing two CO2 gas lift installations in the Denver Unit San Andres CO2 flood. Results have been mixed. One of the two has been converted to a flowing well. The other remains in operation This paper presents an overview of CQ gas lift candidate selection, equipment and selection and performance results of the CQ2 gas lift test.

Coiled tubing fracturing has been widely used as a method of stimulation for the coal seam on the Vermejo Park Ranch. The purpose of this paper is to compare associated cost, production results, and differences in methodology between coiled tubing fracturing and conventional fracturing. The comparisons will be drawn between a sampling of 90 wells completed on two different areas of the field. Past stimulation (conventional fracturing) was done with stage work pumping down casing. This would affect 3 to 9 stages per well during pumping. Current stimulation being done on the Vermejo and Raton coal seams utilize coiled tubing (coiled tubing fracturing). The CT fracturing process increased the number of stimulation stages to 4 to 18 per well. This allows for a more accurate placement of proppant and a more effective stimulation of the producing zones in the well.

Coiled Tubing has been used in oil and gas operations for many years, and has proven to be a very efficient, reliable, and economic tool. The coiled tubing technology has been utilized for drilling, completions, workover, stimulation, and plugging & abandonment work for decades, with considerable success. Coiled tubing for use in artificial lift operations has been somewhat limited, but in the economic environment existing today, new opportunities have been recognized. This paper is focused on three main segments: CT-Lift in normal, rod-pumped wells where sand and scale may be problematic; CT-Lift in monobore wells or where damaged casing may preclude other options; and CT-Lift in gas
well deliquification, where the coiled tubing essentially provides lift options both as a velocity string and as a reciprocating pump string to lift liquids which accumulate at the bottom of a well.

Spraberry operators in West Texas have been fighting casing leaks caused by the corrosive fluids in the San Andres formation for years. Water produced by the Dean, Upper and Lower Spraberry formations is disposed of into the San Andres. There are possibly thousands of Spraberry wells that were drilled and completed without getting cement across the San Andres. This has resulted in plugging many of these wells. Spraberry wells will produce 5 -10 BOPD for decades, but when the corrosive waters from the San Andres cause casing leaks, it becomes uneconomical to continue producing these wells. This paper will discuss the combination of slimhole conversion and the installation of a coiled tubing rod string system to solve the casing corrosion problems in wells that are usually considered P&A candidates. The development of the coiled tubing rod string system will be looked at. Case histories will also be presented.

In the early years of emulsion treating in the oil field, heat and settling were the only major factors employed. Large open pits frequently provided the settling time and the sun contributed some heat. "Sunning" was a common practice. Some producers employed crude-oil fired retorts and stills to reduce the water content of crude. Large boilers were frequently used to heat tanks of emulsion to facilitate settling of water and emulsion. The large amounts of unresolved emulsion from such operations were usually burned as a means of disposal. With the advent of chemical and electrical treatment, the above procedures were gradually replaced. The use of some heat has continued to the present day but treating temperatures have gradually been reduced with many treating plants operating at ambient temperature. Required settling time has also been drastically reduced over the years. For the most part, the energy required to heat crude as part of the treating process, has been supplied by products produced on the lease so has not been recognized as an expense. Losses in crude gravity and volume, sustained as a result of heating, were judged to be insignificant and difficult to measure and had little or no impact on the value or volume of product sold. In past years, heat may have been a low cost factor in treating. Today, with the shortage of fuel and its increased cost, the economics of the use of heat is worth reevaluating. Before assessing the possibility of reducing heat in oil treating, however, a review of emulsification and oil treating is in order to better understand the role of heat.

Use of Coiled Tubing in underbalanced acid washing is becoming more prevalent in carbonate wells with H2S production. Corrosion testing under pressures and temperatures representing downhole conditions is used to qualify a corrosion inhibitor loading. Sour conditions warrant testing with differing amounts of H2S in the gas phase. Safety factors, weight loss and pitting guidelines are employed in the inhibitor design to ensure continued integrity of Coiled Tubing. The thin wall of these tubulars makes corrosion control of the utmost importance. Evaluations of Coiled Tubing after acid treatments examines the surfaces for defects and uses the perlite layer at the concentric center of the tubing wall to determine material losses. Comparisons of laboratory tests to effects on Coiled Tubing, used to treat wells producing from 0 to 60% H2S at temperatures of 75_ to 110_C (167_ to 230_F) are presented. Specifically material deterioration and surface evaluations are compared.

The collar size separator is used to separate liquid from free gas downhole in a well before the liquid is drawn into the pump. The pump and pumping system are much more efficient if gas free liquid is drawn into the pump chamber and the pump is full of liquid rather than having some free gas in the pump chamber.
If liquid is available to fill the pump, additional production will be obtained from the well if the pump chamber if filled completely with liquid. Also, the loading on the pumping system is much better and the pumping equipment will last longer before requiring service.
The separation process in a downhole gas separator is very complex. An animation shows the behavior of gas and liquids in a separator when typical concentrations of liquid and free gas are surrounding the gas separator and pump. The animation is to scale and duplicates the performance of an actual well. the flow of liquid and various sizes of free gas bubbles are shown to help the viewer understand the process of separating free gas from liquid. The flow rates in the separator and dip tube are determined from calculated plunger velocity and production rates of an actual well.

Although the oil industry has long been concerned with the efficient production and recovery of oil and natural gas, present-day regulations, conservation practices, and gas values necessitate review, on a lease by lease basis, of the feasibility of efficiently recovering very small quantities of gas which may be gathered at several ounces of pressure. The rotary gas compressor, which is readily adaptable to compressing very small volumes of gas, provides a means for the recovery for use or sale, of gas at very low pressure. For efficient use of a low pressure recovery system all possible sources of low-pressure gas from the casing head to the stock tank must be evaluated for quantity and liquid hydrocarbon content. Whether low-pressure gas is sufficient to justify an installation is present must be determined. This gas, though small in volume, is usually rich in liquid hydrocarbon content. In some fields where the bottom-hole pressure is very low and the formation permeability is very high, a reduction in formation back pressure may result in an increase in Oil production rate. This reduction in back pressure can be accomplished by elimination of flow-line back pressure on the casing head by installation of a separate gas-gathering system.

Many gas wells drilled today are completed over 100 ft or more of gross pay interval to maximize deliverability, reserves, and revenue. Formation permeability of these wells is usually very low (less than 1 md). Use of conventional transient pressure analysis to understand formation properties is seldom done because of time (many days or even weeks) needed to acquire correct answers. Knowledge of producing zones and their respective amounts are rarely studied. Such limited knowledge concerning formation properties (permeability, pressure, drive mechanism, etc.) and flow profiles can often lead to poor reservoir management throughout the life of the field and eventually leave many thousands of dollars of reserves behind. Combining production logging with the transient rate and pressure analysis (TRAP*) allows one to identify the wellbore's flow profile and formation flow properties such as permeability, average reservoir pressure, and skin factor (near wellbore and total skin) in less than one day. Such combination testing can identify flow regime, drive mechanism, coning or fingering problems, unusual pressure or zonal depletion, presence of crossflow, scale, or plugged perforations; all of which if identified in time, can be used positively to maximize production and revenue. The TRAP technique uses the production logging tool. First, up and down passes over the perforated interval are made prior to the well test to identify the well's flow profile. Production logging passes made at varying flow rates can further be used to identify the reservoir flow behavior, and the associated reason. For the well test part, the TRAP technique incorporates measuring changing rate data with the corresponding pressure data during a buildup, drawdown, or multi-rate test. Using the principle of superposition (continual integral 1, it eliminates wellbore storage problems and identifies formation flow properties in a very short time frame. The TRAP technique is illustrated through the analysis of two deep gas well tests.

The original stimulus for in situ combustion as an oil recovery tool was the presence of large quantities of "unrecoverable" low gravity, high viscosity crudes. Since most of these oils are likely to be recovered only by thermal methods. In situ combustion has be regarded as a recovery tool primarily adaptable to these so-called unrecoverable crudes.

This paper will concern itself specifically with the methods used by commercial banks in financing the development of oil and gas reserves both in the U.S. and overseas and both onshore and offshore. It must be emphasized at the outset that banks do not finance wildcat wells and, in fact, only loan money on proven reserves. This does not mean that the field must be developed nor does it mean that the reserves must be producing, but rather the field must be defined with enough wells drilled to assure the bank engineer or the bank's consulting firm that the reserves are proven.

This paper covers the four principle causes of failure in sucker rod strings: corrosion, improper joint make-up, poor operating and running procedures and improper string design. Ways and means of preventing such failures are suggested.

De-watering techniques using soap sticks vary and are dependant on the completion profile. Vertical completions require a soaping routine significantly different than deviated completions. The factors that make horizontal profiles difficult to plunger lift are overcome with an optimum application of soap sticks and well control. This paper includes case histories, water/hydrocarbon percentages and automation options

The Gibbs method has been the most widely used method for calculating downhole data in sucker rod pumping. This paper presents how the Everitt-Jennings algorithm was modified and applied to the calculation of downhole position vs. time and load vs. time data.
This modified Everitt-Jennings algorithm incorporates iteration on the net stroke and damping factor along with a fluid level calculation as part of the calculation. This paper compares the downhole cards calculated from surface data retrieved in the lab and field, using the modified Everitt-Jennings algorithm and the Gibbs method.

This paper presents the advantages and disadvantages of the class I and class III lever system varying geometry pumping units. By significantly modifying the lengths of the 5bar linkage systern that controls the geometric motion of the polish rod, varying geometries have been achieved in class I units. Varying geometry is achieved when the upstroke of the pumping unit is accomplished in greater than 180 degrees of crank-arm rotation and the downstroke in less than 180 degrees. Previously varying geometries were generally limited to the class III lever system design pumping units. This paper will discuss and compare class I and class III lever system varying geometries.

The recently published API-RP-11L, Recommended Practice For Design Calculations for Sucker Rod Pumping Systems", takes into account many more well variables than were previously considered in sizing pumping equipment. This paper compares the new API method with the more conventional, simplified method which has been used for so many years. Direct comparisons are made between maximum polished rod load, minimum polished rod load and peak torque on the gear reducer. Both the API method and the older method are then compared with measured results taken from 77 wells covering a wide range of conditions.

This paper discusses the comparison of conventional transient analysis and type curve analysis (Hadinoto-Raghavan) in computing reservoir parameters for a West Texas carbonate reservoir using pressure falloff data taken from moderately fractured water injection wells. The theory and application of conventional analysis and type curve analysis to pressure falloff testing are discussed. Included are example calculations showing excellent agreement in computing water xf, using the two methods. formation capacity, kwh, and fracture length,

The proper design of a continuous flow gas lift installation depends on accurate well data. In many instances, gas lift installations are made with a complete lack of vital well information. For this reason a flowing pressure survey is beneficial after the first installation in order to allow a correct respecting of the valves. In many instances, however, good has lift installations have resulted even with a minimum amount of well information. It is generally conceded that the most important factor in continuous flow design is the determination of the correct point of gas injection. Past well performance has shown that the lower the gas injection point, the lower the injection gas-oil ratio. The principal governing factors in design are (a) the available injection gas pressure and volume, (b) the wellhead tubing back pressure, (c) the flowing bottom hole pressure, (c) the flowing bottom hole pressure, (d) the well fluids, which include oil, gas, and water, and (e) the size and depth of the educator tube.

Production from thirty-two horizontal Devonian wells in the Permian Basin was studied in detail to determine if the impact of various completion methods might be distinguished from an existing reservoir overprint. Flowing transient pressure analysis was utilized to determine effective permeabilities and contributing lateral lengths. Production and economic performance were normalized for permeability, productive zone height, and initial static reservoir pressure on each of the wells, so that examinations into various completion processes would be more meaningful. Some of the wells in the study were completed with cemented liners, while the remaining wells were completed with predrilled uncemented liners. A direct comparison is made between the two completion styles. A variety of stimulation processes were employed and examined. Recommendations for various completion processes are presented, based on results of the study and industry-accepted rock mechanics concepts.

Usage of fiberglass sucker rods have proven to be the most efficient means of producing artificial lift wells in the Pioneer Natural Resources, Spraberry Trend Area. Fiberglass/steel designs are being installed on all new drilled wells and will remain in place for the life of the well. In this paper examples will be given of production improvements when going from an all steel to a fiberglass/steel design, various designs which decrease string weight 13 to 26%, benefits of the lighter more elastic rod and comparison of failure data. Procedures used by Pioneer will be discussed to assist operators in selecting the best design for different well characteristics.

Curable resin-coated proppant (RCF") is used in hydraulic fracturing treatments primarily as a means of preventing or reducing proppant flowback during post-frac clean-up and production. The RCP is generally placed in the fracture with water based crosslinked fluids. In order to effectively remove these viscous fluids which are detrimental to fracture conductivity from the proppant pack, it is necessary for a reduction in the fluid's viscosity to occur. This reduction in viscosity, or breaking, may occur either (1) thermally (2) with the addition of enzyme breakers! or (3) with the addition of oxidizing breakers, depending on the fluid used and the bottom hole temperature of the well. Laboratory studies to determine the effects of various commercially available curable RCP's on breaking of commonly used fracturing fluids are presented in this paper. Fluids studied include linear, as well as borate and transition metal crosslinked guar and hydroxypropyl guar. The chemical breakers studied include an enzyme, an oxidizer and an oxidizer used in conjunction with a free radical initiator. Additionally, the effects of these various chemical breakers on the compressive strength development of the consolidated proppant pack is investigated.

Curable resin-coated proppant (RCF") is used in hydraulic fracturing treatments primarily as a means of preventing or reducing proppant flowback during post-frac clean-up and production. The RCP is generally placed in the fracture with water based crosslinked fluids. In order to effectively remove these viscous fluids which are detrimental to fracture conductivity from the proppant pack, it is necessary for a reduction in the fluid's viscosity to occur. This reduction in viscosity, or breaking, may occur either (1) thermally (2) with the addition of enzyme breakers! or (3) with the addition of oxidizing breakers, depending on the fluid used and the bottom hole temperature of the well. Laboratory studies to determine the effects of various commercially available curable RCP's on breaking of commonly used fracturing fluids are presented in this paper. Fluids studied include linear, as well as borate and transition metal crosslinked guar and hydroxypropyl guar. The chemical breakers studied include an enzyme, an oxidizer. and an oxidizer used in conjunction with a free radical initiator. Additionally, the effects of these various chemical breakers on the compressive strength development of the consolidated proppant pack is investigated.

Increased demand for crude oil and the higher prices being paid for petroleum products have caused a resurgence of activity in the Spraberry Trend of West Texas, (Fig. 1). Even though it is one of the largest producing areas in the industry it has always been somewhat of an enigma to those working with it. However, with proper planning and execution of the completion phase, new wells in the Spraberry-Dean sections, and re-. completions in the Dean zone can be economically attractive. The Spraberry and Dean zones are primarily siltstones with very low matrix permeability and porosity. Extensive natural fractures occur throughout the zones. It is the existence of these fractures that provides enough fluid movement and fluid storage to make completion from the zones economically feasible. Due to the nature of these formations, they require a successful hydraulic fracture treatment to provide the needed productivity. Two very influential factors to be considered in planning the stimulation treatment are: zone separation and fluid selection. In order to properly stimulate each zone, it is necessary to keep them separate during the stimulation process. The existence of natural fractures favors extension of the induced fractures beyond the vertical limits of the perforated intervals. In addition, there is a significant difference in the fracturing pressures of the zones, thereby creating a pressure differential across any unperforated interval. It is general practice to maximize the length of this unperforated zone of separation. One popular method for staging the subsequent stimulation treatment is the "ring and bomb" procedure; another is to take advantage of this natural pressure difference between the Dean and Lower Spraberry zones to effect sequential stimulation without benefit of mechanical separation. When stimulating formations with low permeabilities it is necessary to create deeply penetrating fractures in order to obtain adequate drainage. In the case of the specific formations under consideration, large induced fracture heights occur regularly. The end result is the creation of very large fracture areas requiring large quantities of frac fluids. Therefore, it is very important that the fluid chosen provides a balance of fluid efficiency, cost, characteristics. and clean-up Production data on a well-to-well basis is erratic; however, studies of selected groups of wells lead to the general conclusion that bigger frac jobs provide for more ultimate oil recovery. This return on investment is an exponential function and experimentation is still being conducted in an attempt to better define the optimum limits. In addition to fracture penetration, the sand program used and the fracture widths created seem to also have an effect on the production history.

Beam pumping systems are operated in challenging and hostile environments due to the ever increasing demand to produce oil in a fast and efficient manner. The goal of this project is to increase the efficiency of these beam pumping systems by studying and optimizing some of the critical factors affecting sucker rod

Beam pumping systems are operated in challenging and hostile environments due to the ever increasing demand to produce oil. Marketing research revealed the fact that 70% of failures in this industry were rod pin failures. An in-house research & development project/experiment was conducted to address some of the critical factors governing rod pin failures. The experiment uses core engineering concepts of stress, strain, torque and circumferential displacement and explicitly answers the following questions. A) How does the current displacement values affect rod-coupling make up and are they accurate? B) What is the best type of lubrication technique (dry or wet face make up) for the application of rod-coupling make up and why? C) What is the life of a sucker rod or what is the optimal number of make ups on a sucker rod?