CO2 Flooding for EOR is in its infancy.

This paper discusses field facilities problems that were experienced during the initial construction and during the actual operations over the last two years. Furthermore, design and operational considerations and changes which have been made will be discussed for future CO, projects. For the purpose of this paper, four areas of the CO, project facilities will be discussed: the CO, injection facilities, the field production facilities, the gas collection facilities, and the excess water handling facilities.

Once it was decided in 1984 to inject CO2 in the Willard Unit (part of the Wasson Field at Denver City in West Texas), determination had to be made whether to automate the project and, if so, to what extent. Why the decision was made to fully automate the project and detailed descriptions of the automation system are the subjects of this paper.

The increasing use of CO2 in varied oilfield applications generates the need for a thorough knowledge of CO2 properties. These properties are responsible for the way CO2 must be handled in order to use it safely and effectively. The chemical and physical properties will be discussed for CO2 alone and in combination with other liquids and the mixtures subsequent affects on equipment. These characteristics and effects can cause numerous safety problems. Safety procedures to be discussed include logistics, maintaining breathable air quality, and several aspects of metal integrity.

With the advent of numerous CO, injection projects, the need has arisen for processing variable composition gases containing over 90% COz. Traditional gas sweetening plants were geared for removal of small amounts of CO2 (and H2S) from natural gas streams. Enhanced oil recovery projects require gas processing plants to remove methane, H,S and NGL's from CO2 laden gas to produce purified CO2 for reinjection.
Of paramount importance is the efficient recovery of the ethane and heavier NGL's, as they represent a key revenue stream for project viability. Enhancement of the NGL content of the produced gas by crude stripping is recognized in pilot and actual projects. Design of process facilities to economically recover the NGL's and purify the CO2 represents an interesting challenge for the gas processing industry.

Iron sulfide scale had caused a number of short runs in producing wells in this West Texas waterflood. A team of producing company engineers, operations personnel, chemical company technicians, and submersible pump company personnel was formed to identify the problem and research methods to correct the situation. This paper presents a history of the field, problems encountered, characteristics such as loss of production that indicate downhole pump problems, and amp chart review. Chemical analysis of the produced water, along with scaling tendencies, were monitored. Metallurgical analysis of the pump parts exposed to the water, and detailed equipment teardown analysis helped identify the root cause problem. Once identified, steps were taken to reduce abrasive wear by coating pump stages to forestall the problem.

Coefficients of isothermal oil compressibility are usually obtained from reservoir fluid analysis. Reservoir fluid analysis is an expensive and time consuming operation that is not always available when the volumetric properties of reservoir fluids are needed. For this reason correlations have been developed and are being developed for predicting fluid properties including the coefficient of isothermal oil compressibility. This study developed a mathematical model for predicting the coefficient of isothermal oil compressibility based on Peng-Robinson Equation of State (PR EOS). A computer program was developed to predict the coefficient of isothermal compressibility using the developed model. The predicted coefficient of isothermal oil compressibility closely matches the experimentally derived coefficient of isothermal compressibility.

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.