The sucker rod pump is the oldest and still the most widely used means of artificially lifting oil from the well bore. With the demand for higher volumes, from greater depths, with high gas-oil ratios and the use of propping agents in fracturing, the service and performance of the down well pump is greatly impaired. Careful selection of pumps and operating techniques will increase the performance and insure an economical operation.

Ten years age the name "Thermal Recovery" was usually applied to the forward combustion oil recovery process. Today, so many variations of oil reservoir heating methods have been proposed and tested that "Thermal Recovery" now has a far more general meaning. Any oil recovery process which depends upon application of heat to a reservoir is a thermal recovery process. This classification includes: (1) production well heating, (2) both forward and reverse combustion, (3) continuous hot-fluid injection (such as a steam or hot-water injection, (4) intermittent hot fluid injection (such as the push-pull steam injection), (5) use of nuclear devices, (6) electrolinking or electrocarbonization. . . It is the purpose of this paper to summarize sources of design information available for these thermal recovery processes.

The purpose of this paper is to outline and illustrate the calculations required to design a closed rotative gas lift system. Design considerations that are required for continual operation of a closed rotative system without make-up gas after initial charging are discussed. Detailed calculations for a single intermittent well system are offered. These calculations are presented in a step-by-step manner. The effect of expanding the system to include other wells is illustrated.

Ultra-high-slip motors with speed variation capabilities in the range of 45% have been used on beam pumping installations for more than six years. As various producing companies started trying these motors, many improvements in system operation were noted, including: 1. Reduction in peak polished rod load 2. Increase in minimum polished rod load 3. Improved rod life 4. Reduction in peak torque by the API Torque Factor Method 5. A greatly altered dynamometer card shape which showed a tendency to approach the rectangular or parallelogram configuration 6. More production at the same strokes per minute 7. Greatly reduced current (ampere) peaks 8. Greatly reduced RMS (thermal) ampere requirement with a resulting improvement in power factor 9. A much steadier energy (kilowatt) requirement with frequent reductions in total kwh required. 10. Reduced distribution system voltage drop 11. Slower and smoother start-up of the pumping system with a visual recognition that its start-up was less strain on all components of the system 12. A greatly reduced start-up current demand which reduced the possibility of voltage collapse from heavy system loading. These dramatic results created much enthusiasm among those who were involved with the operation and use of the motor. It was assumed by some that all these dramatic results would be obtained on every well in every condition, but that was not the case. On some wells no improvement in dynamometer card shape or rod loading was noted with no apparent improvement in torque loading on the gear box. These tests, which were seemingly failures, caused many interested industry people to doubt the value of an ultra-highslip motor. Some even stated that it had no value or was detrimental to the system. Many heated and enlightening discussions ensued which contributed greatly to the present understanding of the total system operation.

This paper will stress the importance of understanding the various types of corrosion which occur in a well; to do this it is necessary to understand why and under what conditions they occur. Then, the proper cementing composition and procedure can be selected to help prevent the problem from reoccurring.

A 4-ft by 12-ft transparent, vertical fracture model is used to study the prop-carrying abilities of both non- Newtonian and Newtonian fluids. The design parameters and difficulties encountered in building and operating the model are discussed. Solutions to problems such as uniform distribution of prop in the sample area, uniform flow across the sample area, and reduction of end effects are described. A novel technique is used to record and reduce the prop trajectories. Observations of suspended prop flow in vertical fractures are presented.

The reservoir engineering aspects of the design of a major West Texas co2 flood are presented. The design included (1) a detailed fieldwide geologic study to characterize the principal Yates reservoirs, (2) a CO2 injectivity test to identify any reduction in injectivity either during or following CO2 injection, (3) laboratory work including oil-CO2 phase behavior, slim tube tests with pure and contaminated CO2 corefloods to determine recovery of waterf lood residual oil by CO2 flooding, (4) reservoir simulation to predict flood performance. A comprehensive waterflood evaluation proceeded the selection of average pattern models ~/for reservoir simulation. These three-dimensional models, which have up to twelve layers each, were history matched over the 33 year waterflood period. Predictions were made for continuation of the waterflood and for CO2 flooding. Additional reservoir simulation was conducted to determine the optimum economic co2 slug size and to study the differences in recovery efficiency between line drives and five spots. Scale-up procedures were developed to predict from the average patterns the incremental oil production for the 3840 acre project area. It is predicted that CO2 flooding will recover an additional 8% of the original oil in place (OOIP). The optimum CO2 slug size lies between 38% to 60% hydrocarbon pore volume (HCPV). The optimum water-alternating-gas (WAG) ratio is 1: 1. Gross and net CO2 utilization ratios are 12 and 4 MSCF/STB (2136 and 712 m3/m3), respectively.

A general method for designing submersible electric pumping systems is presented. The technique is based on a mathematical model of the pumping system which includes mechanical, fluid dynamical and electrical simulations. Basic parameters which affect the design of a submersible electric system are discussed. To illustrate the technique, applications are made to high water cut (non-gassy) wells, high GOR (gassy) wells, variable frequency drives and tapered pumps.

This discussion is limited to salt water disposal systems where the salt water is to be injected into a subsurface formation. The subsurface formation may be the same formation from which the water was produced or some other one. The injection of salt water may be solely a means of disposal or it may be injected as a part of a waterflood or pressure maintenance project. Systems for subsurface disposal of salt water will usually include the injection well, injection plant, treating plant and the salt water gathering system. The injection wells, injection plant and treating plant, as well as the source and disposition of the water, will be discussed only as they may influence and require consideration in the mechanical design of the salt water gathering system and the time for initiating such design.

In order to meet the codes and standards regarding equipment to be used in hydrogen sulfide service, there are several basic design criteria which must be met. The regulations specifically referred to in this technical paper are the Statewide Rule 36(l) as established by the Texas Railroad Commission, and Standard MR-Ol-75(2), as established by the National Association of Corrosion Engineers (NACE). Other states are now establishing similar rules to Texas Rule 36 for the protection of the general public from the harmful effects of hydrogen sulfide when associated with the producing of oil and gas. The design criteria covered in this paper are those which meet the minimum requirements of Texas Rule 36 and/or NACE MR-01-75. Additional design criteria should be added to these minimum standards if the producer or operator of the lease determines that the concentration of the hydrogen sulfide is high enough to warrant increasing design requirements. As stated in NACE MR-01-75, "It is the responsibility of the user to determine the expected operation conditions and to specify when this standard applies." It is the opinion of the author that the user then has the responsibility to determine the occurrence of H2S and its concentration. He then should inform the manufacturers and/or suppliers of equipment so that they may adequately design equipment with the proper safeguards to handle the oil and/or gas containing H2S. The user also has the responsibility to provide proper training for operating personnel in using the equipment. The user is expected to provide warning signs and security to protect the general public from danger when handling oil and/or gas which contain H2S.

Effective mud removal of drilling fluids from the wellbore is still a major problem in cementing. Although good pipe centralization has been known for years to be one of the keys to the success of the operation, most current design procedures do not allow pipe standoff to be taken into account. When attempting to displace a mud in an eccentric annulus with a fluid thought to be in turbulent flow, it is shown that the displacing fluid can channel through the mud. An explanation for this phenomenon is given and a solution is proposed. When turbulent flow displacement cannot be achieved, displacement at lower rates has then to be considered and associated criteria leading then to improved mud removal efficiency are also discussed. These displacement guidelines, as well as other more general considerations, show the need for spacers having well controlled engineering properties: compatibility, rheology, ability to suspend weighting agent, fluid loss. Examples of such spacers are presented and the properties of laboratory and field prepared samples are compared.

Effective mud removal of drilling fluids from the wellbore is still a major problem in cementing. Although good pipe centralization has been known for years to be one of the keys to the success of the operation, most current design procedures do not allow pipe standoff to be taken into account. When attempting to displace a mud in an eccentric annulus with a fluid thought to be in turbulent flow, it is shown that the displacing fluid can channel through the mud. An explanation for this phenomenon is given and a solution is proposed. When turbulent flow displacement cannot be achieved, displacement at lower rates has then to be considered and associated criteria leading then to improved mud removal efficiency are also discussed. These displacement guidelines, as well as other more general considerations, show the need for spacers having well controlled engineering properties: compatibility, rheology, ability to suspend weighting agent, fluid loss. Examples of such spacers are presented and the properties of laboratory and field prepared samples are compared.

The sucker rod string for rod pumped wells can be adequately designed from hand calculations using API RP 11L1 or computer programs. While these methods will provide very good approximations of the loads and related stresses on the sucker rods and pumping system, they do not consider the loads the downhole equipment will be subjected to if a downhole pump is stuck and the rods are used to try to unseat the pump.
This paper will discuss the basic loads on the sucker rods when they are subjected to the fluid loads and forces when trying to unseat the pump. Additionally, results from testing downhole seating cups and mechanical bottom lock assemblies will be provided. Since the pulling unit weight indicator may not be accurate, the calculation converting unseating loads to maximum inches of pull or rod stretch will be provided. Recommended maximum pull weight on various grades of sucker rod diameters and grades will be provided from one sucker rod manufacturer. Finally, it is recommended that a check on the rig hoisting equipment (rod elevator and sucker rod hook) capacity is obtained to make sure the pulling system does not become overloaded when trying to unseat the pump.

Numerous technical papers have been written on the subject of analyzing the pressure-decline data from a mini-frac. Most of the publications written, however, have dealt mainly with the theoretical modeling of the pressure decline and not the practical application of performing a mini-frac in the field. The intent of this paper is not necessarily to discuss the theoretical analysis and design applications of modeling mini-fracs, but to discuss the practical steps involved to properly design, execute and evaluate a mini-frac. The basic concept of the mini-frac is presented. Guidelines are given on how to design a mini-frac, record bottomhole pressure (BHP), obtain closure and interpret the data. Field case studies are presented which illustrate the step processes involved in performing and evaluating a mini-frac.

ARCO Oil and Gas Company started work on a tertiary CO2 Pilot in the Garber Field during early 1980. The purpose of the pilot was to investigate the CO2 flooding of relatively shallow sands which were previously waterflooded to depletion. The pilot is in the Crews sand, a shallow Pennsylvanian sand, located at an average depth of 1950 ft. The main pilot is a 10.4 acres, normal 5-spot, which is enclosed by backup water injectors and outside producers. It was initially waterflooded to raise the reservoir pressure and to establish a base production curve. CO2 injection started in late October 1981. In all, 27,000 tons of C02, representing 35% of HCPV within the effective area, was injected in this pilot. The response of the pilot has been very encouraging. It has already recovered over 70,000 STBO. Ultimate recovery should exceed 14% of the original oil in place within the effective area. The success of this pilot opens up possibilities for shallow reservoirs, which had not been seriously considered for CO2 flooding.

The important factors concerning gear reducer design are discussed. Various phases of operational and maintenance control and the effect of improper application of these principles are reviewed.

The controlling features in a designed beam pumping system are: the desired production volume, optimum subsurface pump, gas anchor, sucker rod string including a sinker bar section, polished rod, tubing, V-belt drive, prime mover and the pumping unit. The design of each of these components is discussed in a step-by-step fashion. The governing assumptions are given, and all pertinent calculations are presented. The procedure, together with the necessary exhibits, is presented in such a manner that it can be used to optimize the design for beam pumping equipment on wells determined to be suitable for that type of artificial lift.

The purpose of this paper is to outline the procedure for designing an efficient closed rotative gas lift system. The system discussed includes both continuous-flow and intermittent gas lift wells. The importance of considering future as well as present gas requirements is noted. Adequate capacities of the high-pressure injection and the low-pressure gas systems are emphasized. Intermitting gas lift characteristics are reviewed to emphasize further the necessity for adequate volumes in both the low-and the high-pressure systems. Equations for calculating the gas volumes and the pressure losses in these systems are offered. Information required for properly sizing the compressor by the manufacturer is outlined. A flow diagram of a rotative gas lift system complete with regulators is presented. The purpose and the location of each regulator are given. Considerations and operational practices for efficient overall operation are noted. The paper is concluded with example calculations of a closed rotative gas lift installation for an eight-well system.

The South Cowden (San Andres) Unit is the site selected for one of three mid-term projects to be conducted under the DOE Class II Oil Program for Shallow Shelf Carbonate Reservoirs. The proposed $21 million dollar project is designed to demonstrate the technical and economic viability of an innovative CO2 flood project development approach. The new approach employs cost-effective advanced reservoir characterization technology as an integral part of a focused development plan utilizing horizontal CO2 injection wells and centralization of production/injection facilities to optimize CO2 project economics.- If proven successful, this new approach will help improve the economic viability of CO2 flooding for many older, smaller fields which are or soon will be facing abandonment.

There are a number of important considerations in the design of any sucker rod pumping system. To get the best design for a specific application each of these variables must be evaluated in terms of the particular requirements of that specific system. A system which might be ideal for the operating conditions of one area might be a very poor selection for use in another area with different operating conditions.

In designing a submersible pump for an oil well application, the engineer can benefit greatly from the proper use of well data and conditions under which the pump will be operating. It would, of course, be easy to select a pump size if it were already established that the well could produce some given amount of fluid needed to make it a profitable operation. However, the submersible, like any other piece of equipment must be designed with a number of factors taken into account. Accurate well data and well-kept well production records can be of great value to the person designing a submersible installation.

Three dimensional hydraulic fracture simulators have become increasingly popular in the Permian Basin. The choice of input parameters to these simulators can be critical to obtaining reasonable results. When sufficient effort is put forth to estimate these parameters, fracture height can be predicted prior to the job. This can be critical if water bearing zones are in close proximity to the hydrocarbon zones of interest. Field examples are discussed from the Delaware, San Andres, and Spraberry to demonstrate the value of proper parameter selection for 3D models in predicting fracture height.

The fiberglass sucker rod design process has come a long way since the introduction of fiberglass sucker rods in the late 1970"s. For the past 15 years fiberglass sucker rods have continued to gain acceptance in the oil field as a viable means to enhance the capabilities of beam pumping systems. With the advent of affordable predictive computer programs, in combination with this continued success and acceptance, more producers are finding themselves faced with the challenge of designing beam lift systems that utilize fiberglass sucker rods. The purpose of this paper is to give the designer of beam lift systems some guidelines to become more effective when designing optimum fiberglass sucker rod beam lift systems.

The presence and magnitude of natural fractures in a potentially productive zone may have a significant effect on the completion of that zone. Their existence may dominate the pore space of the rocks and control the production rate. In addition, the method and materials required to stimulate this heterogeneous system may require special attention. This paper discusses the detection of fractures from the pressure buildup behavior of a drillstem test, and how this behavior may be distinguished from unconnected layered zones and flow capacity discontinuities. A quantitative analysis making this distinction is demonstrated by a Horner plot, square root of time plot, and Gringarten curve fit. The magnitude of the fractures may he estimated.

Abnormal Pressure can be detected during drilling operations in world-wide environments. Five practical detection tools: rate of penetration, shale densities, "d" exponent, flowline temperature and pseudo-porosity have been used for this purpose. Actual formation pressures have been predicted in certain instances. Some, or all of these tools were utilized in the U.S. Gulf Coast, African area, Southeast Asia and the North Sea.