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.

A significant application of multiple tracers is their use in tracing different proppant concentration stages and/or types of proppant to determine their effective wellbore distribution at the fracture entrance. Extensive fracture intervals heterogeneous formations with large containing multiple perforated intervals or hydraulic fracture treatments that utilize the limited entry technique provide one of the best opportunities for using multiple tracers to evaluate proppant distribution. Historically, single isotope tracers (usually Iridium baked or painted onto frac sand) and conventional gamma ray - temperature logs were employed to ascertain fluid and/or propped fracture the wellbore. height at Deviated wellbores or fractures whose azimuth was not vertical caused this analysis technique to yield a lower boundary on fracture height since the full extent of the induced fracture may occur outside the depth of investigation of the scintillation tool being used. Over the last several years, the use of multiple gamma ray tracers in conjunction with advanced gamma ray spectroscopy logging methods has undergone significant evolution and improvement. One of the principal advances is software to differentiate up to four isotopes and their presence inside or outside the wellbore. Much research has been devoted to the development of radioactive particles which exhibit insignificant tracer wash off and offer superior representation of the transport and placement of the medium they are intended to trace. With the single tracer, after-frac gamma ray log approach, if some or most of the radioactive material It washes off of the tagged proppant and becomes dissolved in the fracturing fluid, there was little reason to despair. With the recent advances in gamma spectroscopy tracer logging where both particle and soluble tracers are injected simultaneously with the intent of, differentiating fluid and proppant placement and distribution, this washoff of radioactive material from the tagged proppant has become the subject of great concern. Certainly, the discrimination of propped and induced fracture height becomes impossible if this washoff is significant. Today, proppant tracers are currently available which exhibit absolutely no radioactive washoff and have virtually the same particle size, density, and crush resistance as the proppants. For the application of studying proppant distribution, superior tracers and advanced gamma spectroscopy logging methods are both needed and required.

A significant application of multiple tracers is their use in tracing different proppant concentration stages and/or types of proppant to determine their effective wellbore distribution at the fracture entrance. Extensive fracture intervals heterogeneous formations with large containing multiple perforated intervals or hydraulic fracture treatments that utilize the limited entry technique provide one of the best opportunities for using multiple tracers to evaluate proppant distribution.

There is evidence that the current need for natural gas reserves has made certain low permeability reservoirs, heretofore considered marginal or uneconomical, candidates for development. Accurate estimates of the gas in-place in these reservoirs will not only be important for pipeline contracting purposes, but will become fundamental requirements for establishing the most economic well spacing and the best facilities and operations design. Considerable effort has been directed to the problem of estimating the gas initially in place and in predicting future performance of natural gas wells. Basically, the techniques described in various reviews of the methods used fall into the volumetric or the performance categories. The volumetric technique, based on geological considerations, is useful in the very early- stages of a reservoir's life. The pressure production methods, based on data recorded during the producing life of a well, are generally considered more accurate and can sidestep the error in volumetric estimates caused by unknown reservoir properties. Most theories for estimating the gas in-place have been based on one or more idealizations. Most performance calculations assume Semi-steady-state flow, small and constant compressibility, gas viscosity calculated at an average pressure, radial flow and all other ideal reservoir considerations. Most calculation methods require that the pressures on which the solution is based be weighted average representations of reservoir pressure. With the acceptance of real gas potential, and the development of equations defining the average pressure in bounded reservoirs of different configurations, it becomes feasible to develop a process for estimating the initial gas in-place from shut-in or flowing pressure data that is not stabilized. The method can take into consideration the geometry of the drainage area and the fact that the gas compressibility may vary widely because of large pressure drops in a low permeability system. The equations expressing the semi-steady state pressure drawdown or build-up in terms of the real gas potential at the wellbore are presented as Eqs. (2) and (3) below. In order to prove the validity of the concept, three separate executions of a numerical simulation model were performed to develop pressure production data suitable to check out the new procedure. Two different geometries and two different well flowing conditions were imposed on the numeric models so as to develop data under a range of assumptions. In all instances, a known amount of gas was assigned to the models and a pressure history corresponding to the assigned withdrawal schedule was developed. This pressure history, if correctly evaluated by the proposed procedure, should generate the known gas in-place to a high degree of resolution.

For reservoir history matching, simulated model output is conditioned to observed historical field data by modifying the model parameter so that the simulated data matches the history data. The matched model which is dependent on the historical data utilized for matching is used for reservoir production forecast. The vital question to be answered by reservoir engineers is the waiting period duration in order to have sufficient historical data for matching. In this work an answer is provided for this waiting period. This paper reports cut-off time for sufficient historical data suitable for reservoir history matching. The cut-off time was determined from several history matched scenarios. To calculate the cut-off time, reservoirs with known parameters and twenty four year production data were used as the base case models. Thereafter, simulation models of the actual reservoirs were built. The simulated model was run for 6, 12, 18, 24 and 48 months, respectively, and the simulated production profile matched with their corresponding actual reservoir historical time data to achieve a matched model. The calibrated model was applied to make future reservoir prediction and the simulated model prediction was compared with the base case reservoir production profiles which were known. This approach enabled the determination of historical data cut-off time that is sufficient for good history matching as follows: 1. observed historical data of 18 months are sufficient for a good history match if the simulated model is 75 percent and above close to the actual reservoir description. 2. If the simulated model is between 50

Rod guides used to centralize sucker rods inside tubing have evolved dramatically over the past 20 years. The primary function of a rod guide is to extend the life of the production equipment by preventing metal-to-metal contact. Basically, the portion of a rod guide between the largest O.D. on the rod string and the I.D. of the tubing is all that can prevent the damaging metal-to-metal contact. This protective volume of the rod guide is often referred to as erodible wear volume (EWV). It is an important indicator of rod guide performance. A properly designed sucker rod string with strategically located rod guides can be economically justified in many situations. One way to evaluate the investment is by the amount of EWV. Unfortunately, EVW can be defined in a variety of ways and a lack of standardization creates confusion when attempts are made to compare the EWV of one rod guide with that of another. The definition of EWV has evolved since it was first introduced in 1986. The original definition, which will be referred to as Gross EWV, is the amount of rod guide material outside the O.D. of the sucker rod coupling. It is a simple, easy to measure index. Consequently, it is not prone to measurement or calculation errors. However, Gross EWV neglects the effects of rod guide geometry. Initially this was not a problem because the geometry of the few rod guides on the market were very similar. Therefore, Gross EWV did an adequate job as an indicator. The more recent definition, which will be referred to as Net EWV, is the amount of rod guide material that will erode before the sucker rod coupling contacts the tubing. Net EWV is a more difficult concept and prone to errors in measurement. It is virtually impossible to calculate without sophisticated computer modeling software. However, Net EWV does account for rod guide geometry. It is more representative of true protection and it is a concept that needs to be developed in light of all the new rod guides that are evolving today. The primary objective of this paper is to compare Gross and Net EWV and to suggest industry standards for measuring both. Unless standards are adopted, EWV as an index will continue to be confusing to the industry. One important point to remember is that no definition of EWV really means anything unless the rod string is continuously rotated and the rod guides wear evenly.

A new pressure transient wave method is presented for measuring fluid levels in wells, The method uses flow induced pressure phenomena to measure acoustic velocity externally from the well in a known length of coiled tubing. Similarly with a flow induced pulse in the well a fluid level is measured by sensing the distance traveled by the pressure wave. The method is flexible. The pressure wave can be created automatically or manually by venting a small amount of gas from the well, by abruptly releasing high pressure gas into the well or by implosion if the casing pressure is high. Simplified and less expensive equipment is involved. The method is applicable to routine surveillance, well productivity studies, lift equipment design and reservoir evaluation. Fluid levels measured with the new method compare favorably with those obtained with traditional techniques.

Tracking the fall of the plunger down the tubing can be used to optimize the operation of plunger lifted wells. Acoustic fluid level instruments can be used on plunger lifted wells to acquire a series of plunger/fluid level soundings and/or to record the acoustic signal produced as the plunger falls down the tubing. Five different data acquisition and analysis methods can be used to monitor the position of the plunger, as the plunger falls down the tubing during the controller's shut-in time period. The acquired data is used to determine the 1) fall velocity of the plunger 2) depth to the plunger and 3) time for the plunger to fall to fluid. Results acquired from field case studies from 15 sessions at various wells are used to correlate the various construction features of different types of plungers with their fall velocity. Some construction features cause a plunger to fall rapidly through the tubing, while other features cause the plunger to have a slow fall velocity. By accurately measuring the plunger fall velocity, the proper shut-in time for the plunger lift installation can be determined. The plunger trace measurements will ensure that the plunger has reached the fluid at the bottom of the tubing by the end of the shut-in period. Setting the well's controller to have the shortest possible shut-in time period to allow the plunger to fall to bottom can maximize oil and gas production from plunger lift installations.

A matter of concern in most secondary recovery projects is control of the movement of injected fluids. If the injection pressure exceeds the fracture gradient of the confining layers of rock, the injected fluids will not be optimally placed. Historically, operators have seen evidence of exceeding fracture gradients in pay zones using Hall plots, fall off tests, square root of time plots or step rate tests. All these methods require fracture stimulation of the rock and though they describe the pay zone stresses adequately, they lack data on the boundary rock. Tracer surveys can tell when the fluids have migrated out of zone. Unfortunately, this data is obtained after the fact. Determining the injection pressure limits prior to fracturing out of zone is preferred. With developments in in-situ stress measurements, this data is now available in a timely manner. The methodology proposed is to determine a continuous hydraulic fracture gradient in the wellbore using full wave sonic data and formation pressure data. This has been accomplished on Over 700 producing wells since 1984 to control the hydraulic fracture treatment. Recently, this technology has been expanded to include water injection wells to control the injection process. A discussion of the methodology used follows along with a field example.

In determining the net lift and bottom-hole pressure in a pumping well, the first thought that comes to mind is, "What equipment is necessary?" The dynamometer and its related equipment are the only tools required. The dynamometer test data necessary are the traveling valve check and the standing valve check. Although this sounds simple enough, it should be pointed out that there are several precautions which should be observed in taking these valve checks.

Management has become a professional employing skills and disciplines which are quite independent of trade or professional skills and disciplines. Engineers, accountants, teachers, and doctors can no longer conclude that proficiency in their particular profession gives them proficiency in management, nor does any profession preclude such proficiency. Conversely, it should not be assumed that any particularized schooling will of itself make a manager. Management is a skill in itself, often inherent in professional and skilled people together with their titled skill.

It became apparent some 20 years ago that oil wells produced by artificial lift were becoming more corrosive and more demanding of downhole equipment. This paper relates to the case history of sucker rod coupling failures that caused accelerated attention by manufacturers toward product improvement programs and ultimately the development of the sprayed metal coupling. The metals used and the processes involved in the manufacture of couplings are discussed in some detail.

It is usually a difficult task for drillers to choose a suitable roller cone bit in order to efficiently drill through interbedded formations. When experience and/or drilling log information indicate the interbedded formation is drillable with an insert type roller cone bit, a conical type insert bit is usually chosen because of the durability of its cutting structure. This paper discusses the development and applications of a new type of roller cone bit with chisel inserts that are able to drill very efficiently through interbedded formations. The durability of the new bit is comparable to that of conical insert type bit, but the rate of penetration is significantly improved. The new roller cone bits incorporate new cutting structure with enhanced drillablity, durability, and reduced vibration. Several case studies in western Texas and Oklahoma have been provided in the paper.

It has long been recognized that there exists a significant technology gap between the performance of the best water based drilling fluids (WBF) and invert emulsion fluids. WBF fall behind with respect to shale inhibition, wellbore stability, rate of penetration, and fluid stability. Strengthening of restrictions regarding use and discharge of invert emulsion fluids, coupled with the challenges of extended reach and deepwater drilling (low fracture gradients, narrow ECD windows, high lost circulation risk) have challenged WBF development. The results of several research and development projects into shale inhibition, cuttings accretion, lubricity, cuttings encapsulation and rate of penetration with WBF allowed the stepwise generation of a new WBF designed to approach invert emulsion fluid performance. This paper describes the development of a these inhibitive water based fluids, and the field performance results obtained from these fluids, showing the invert emulsion-like performance and discussing engineering of the new drilling fluid.

Recently, an intrinsically safe, high pressure, gas gun was developed and presented at the 2010 SWPSC. This development was certified for Div 1/Class 1 well locations. Extending this development was the need to manufacture this gun for 5000 psi well service for operations in hydrogen sulfide and carbon dioxide fluid service. This presentation will discuss the industry requirements for materials selection according to standard NACE MR0175/ISO 15156. Also presented will be the main gas gun components in the fluid path and the appropriate selection of materials resistant to cracking and corrosion in this service.

This paper reviews basic techniques required to determine an equation suitable to describe a given set of data points. In general, the data is matched against ten of the more corrrnonc urves encountered by the petroleum engineer. The conversion of each of the ten curves into a psuedo-linear equation is discussed. Coefficients for each equation are determined by the least squares method and the method of averages. A microcomputer program that incorporates these concepts is presented. The program is written in BASIC for the Apple II microcomputer.

The newest technological advancement in the Progressing Cavity Pump (PCP) industry has been the development of composite stators and rotors. Included in this design concept is a reversing of the conventional elastomer and hard surface interface. The stator, in this design concept, is made of a hard composite material and is placed in a steel tube jacket. The rotor can be made of steel or composite material and coated with an even thickness of a soft and durable polyurethane. The urethane offers increased wear resistance and mechanical properties over conventional elastomers and the even thickness offers additional performance enhancements. Also, the elastomeric placed on the rotor offers the well-servicing advantages of the wear element being located on the end of the sucker rod string rather than on the end of the tubing string. The composite PCP becomes a low cost, highly durable PCP that incorporates the emerging even thickness elastomer technology.

Attendees of the annual Gas Well Deliquification Workshop have expressed interest in having a set of industry-accepted recommended practices for selection of artificial lift systems for gas well deliquification. The Artificial Lift Research and Development Council (ALRDC) has initiated a process to define these practices and make them readily available to the industry. This presentation will describe the process being used and the progress that has been made. It will invite participation by others in industry.

Even though progressing cavity (PC) pumps have been used by the industrial world for many years on liquids containing abrasive fluids, PC systems are a relatively new means of artificial lift in the oil field. One of the more obvious differences between the newer PC and the traditional beam pump is that the rod string rotates rather than reciprocates. PC pumps are now being used on increasingly deeper wells and on a wider variety of production fluids following their introduction in shallow wells to produce heavy, sand-laden oil. As a result, PC pumps are earning a place in the market and oil field equipment manufacturers are beginning to develop products for PC systems. One example is rod guides which, until recently, have been designed solely for reciprocating rod strings in beam pumped wells. Lower initial investment, less power per unit of production, more tolerance for sand-laden fluids, and greater production capacities are some of the advantages touted by PC systems. However, maintenance can be more expensive. One reason, which is the driving force behind this study, is that tubing wear opposite rod couplings is more concentrated because the rod string rotates in a stationary position. If well bores were truly vertical and crude oil was free of abrasives and water, rod and tubing wear in either beam or PC pumping systems would be of little consequence. However, in the real world, rods and tubing never hang perfectly concentric and few wells, if any, produce crude oil with undiluted lubricity. Consequently, in both reciprocating and rotating systems, rod and tubing wear accelerates as production rates, hole deviations, water/oil ratios, and sand concentrations increase. As these variables increase, the need for rod guides also increases. When PC's were first installed, operators had no choice but to rely on guides which had been developed for reciprocating pumps to centralize rod strings inside the tubing. Two examples are Huber's New Era Turbulence Breaker (NETB) and Patco's Double Plus (DP) shown in Figures 1 and 2, respectively. Both are the end result of years of research and development. Each guide has fins with an O.D. close to the I.D. of the tubing. The fins have been designed to achieve maximum standoff between the rod couplings and tubing with minimum pressure drop. A third example is the cylindrical unfinned poly guide shown in Figure 3. The poly guide has a smaller O.D. than either the NETB or DP, otherwise pressure drop increases beyond acceptable limits. Because the O.D. is smaller, standoff between the rod couplings and tubing is less. Consequently, the unfinned design is at a disadvantage because it has less erodible wear volume (EWV), as defined in Figure 5, to prevent metal-to-metal contact between the rod couplings and the tubing. In all three examples, the guides are bonded to the sucker rod. In fact, the quality of guides for reciprocating rod strings is frequently judged on the basis of bonding power

Maintaining maximum efficiencies in the pumping of gaseous wells continues to be a major operating problem. Because of wide range of downhole environmental conditions, it is difficult to prescribe a general solution for all wells. More often, a thorough study of downhole conditions must be made. With this information, and through proper application of rod pumps, subsurface gas anchors, and gas separators, a substantial improvement can be made in many wells. This paper deals with the developments in rod pumps and sub-surface accessories, and their design, construction, and application to improve pumping efficiencies where gas is present.