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.

Sucker-rod pumping system is the most numerous among all artificial lift methods used in the Permian Basin. Therefore. continued efforts to improve and optimize sucker-rod performance are imperative for successful operation in this area. The Artificial Lift Energy Optimization Consortium (ALEOC) was formed by eleven oil companies operating in the Permian Basin with the primary goal of improving oil field operations through sharing experiences. The consortium members provided beam pump related data from about 25.000 wells, which is about a quarter of sucker-rod pumped wells in the entire Permian Basin. A database has been developed to combine these data into a single, uniform and consistent format. The database can be queried and analyzed either via the Internet or in the desktop environment. From the query results, one can calculate failure frequencies of pump, rod, and tubing, and summarize the results in various ways. Such analysis will suggest answers to questions like what component is the most/least likely to fail. which operating areas have typically high/low failures, and what is the performance of a company relative to the other companies. Knowing these facts should greatly benefit each company in making engineering and business decisions.

Marked advancements have been made during the past four decades since the first commercial hydraulic fracturing treatment was performed in 1948. The high sand concentration fracturing process is one of the most dramatic of the advancements that have been realized. The central thesis of this paper is the evolution of the high sand concentration fracturing process, and the paper is composed of the following three categories. 1. Development. The high sand concentration fracturing process is presented from its conception in 1960, thru the first experimental treatment in 1972 and the first complete successful treatment in 1976, to the present status of the process. 2. Design. An overview of the procedures and mechanics required to design and perform a successful high sand concentration fracturing treatment is presented. 3. Results. Initial and long-term production increases are presented for high sand concentration fracturing treatments, and where possible, they are compared to conventional sand concentration treatments.

There are a variety of sucker rod grades available today for different pumping environments. In order to optimize the run time of an oil well, it is very critical to choose the correct sucker rod grade for a particular application. There are a lot of physical attributes (engineering attributes) which need to be considered for design aspects of a rod string. Some of the engineering concepts are yield, tensile, load carrying capability, stress-strain curves, elongation, reduction of area and toughness. The first segment of this paper addresses these sucker rod concepts using stress-strain curves. One of the most well known practical problems faced in the field is the selection of sucker rod grade in a high load and corrosive environment. The obvious choice becomes a KD grade sucker rod because HS (High Strength) rods due to their mechanical properties should not be used in corrosive environments. As a result of this, the end users had no choice except to overload KD rods in corrosive environments. UPCO, Inc. has developed and tested a new grade of sucker rod which can be used in higher load wells where high strength rods are not an option due to corrosive nature of the well. The second segment of this paper addresses the development of the new grade of
sucker rod (SD). SD grade of sucker rods fills the application gap between KD and HS rods. SD rods have better load carrying capability than a KD rod and a better toughness than a HS rod.

In a potential gas-bearing Woodford shale reservoir (Ro% = 2.62 and MI = 11.3 DRY GAS) with a standard logging suite [Array Induction

The removal of accumulated liquids from the wellbores of gas wells is a problem which has faced operators for as long as natural gas has been produced. The reduction of deliverability resulting from these liquid accumulations and the expenditure of cash and energy to remove the liquids are at best expensive nuisances, and at worst, economic catastrophes. Many approaches have been taken toward the solution of this liquid removal problem with varying degrees of success. The type of approach taken depends upon a number of factors including the type of liquid to be removed, available reservoir energy, and economic considerations. With adequate available reservoir energy and optimized production practices, expenditures for artificial lift aids may be minimized or eliminated; With slightly less energy to draw upon, these aids may take the form of gas lift or cycled pulsing or purging of the wellbore liquids. The worst conditions, from an economic standpoint, involve those wells which due to pressure decline, excessive liquid influx, or low permeability, require mechanically lifting an unsalable product. This is recognizable as pumping water from gas wells, and is not a new idea to many operators including El Paso Natural Gas Co. which has been operating pumping units on gas wells since 1964. One of the most recent entries in the field of pumping equipment is the pneumatic pumping unit. The units which El Paso now has in operation are proving to be a valuable addition in dewatering low-pressure gas wells. At present El Paso operates some 69 pumping units in the East Panhandle Field in Texas and the South Erick Field in Oklahoma. Of these, six are pneumatic units and the remainder are conventional beam-type units powered by gas-fueled engines or electric motors

In the effort to raise more hydrocarbons to the surface, production practices have evolved which aggravate certain corrosion related problems. One of these problems, corrosion fatigue, is usually associated with rod pumped wells because it has a stress component plus a corrosion component; as wells are pumped harder, stresses are higher and corrosion fatigue becomes more prevalent. Another of the problems becoming more frequent is an indirect result of both harder pumping and depletion of gas pressure in oil reservoirs, and a direct result of certain stimulation methods; oxygen can enter production fluids and alter the mechanism of corrosion in oilfield fluids. This paper outlines diagnosis of these two problems and describes their control with corrosion inhibitors.

The proper and economical operation of pumping wells may be simulated to a good safety program. The problem is always changing, inasmuch as reservoir conditions immediately around the well bore change from month to month.

Diagnostic methods and programs for rod pumping commonly assume that the wellbore is vertical. Applying these methods to deviated wells will result in distortions and inaccuracies when calculating the down-hole pump card. This paper describes a new method for analyzing pumping efficiencies in deviated wells. The method requires a deviation survey for the 3-D borehole trajectory that incorporates the dogleg effect (rod/tubing drag forces) into the solution of wave equation. The program is applicable to wells with bare rods, molded-on rod guides, and wheeled-rod guides or a combination of these. Real examples are shown to compare results from both programs. The deviated program improves the accuracy of the pump card and the card is easier to interpret. Thus, the producing pressure and pump displacement rate based on the pump card are more precise. In addition, the deviated diagnostic program can generate data that can be used to improve the accuracy of the deviated predictive program.

The petroleum industry's need to reduce cost challenges users to select the most effective tubular goods inspection for each individual job to minimize the large expense normally incurred with replacement or repair of defective tubular goods. Several diagnostic tools are necessary to meet the many variable inspection requirements for the different grades of new and used tubing, casing, drill pipe, line pipe, and sucker rods. Inspection methods are available which, if properly employed, should detect defects currently considered hazardous. Those associated with ordering and using tubular goods inspections should insure that each inspection dollar earns a profit; this requires selection of the applicable inspection method for each job and economic considerations to determine if the inspection should reduce cost by minimizing possibility of failure or premature retirement of pipe or rods from service.

Diamond Enhanced Hammer Bits in conjunction with Down-the-Hole Air Hammers have been utilized throughout the 1990's to improve penetration rates in hard formations as well as to reduce deviation and improve overall drilling costs. Significant improvements in bit life have been made by utilizing the 3rd Generation Impax Hammer Bits along with the current Best Drilling Practices that have been developed in the Val Verde Basin. This paper will review these Best Drilling Practices as well as discuss the new technology that was developed for these Percussion Drilling applications.

This paper compares the costs of diatomaceous earth filtration and sand filtration.

The following discussion will be mainly concerned with diatomite filtration of salt water and industrial waste streams and subsequent subsurface injection. Filtration usually follows other treatment methods that may be used. Diatomite filtration is one of the most versatile, reliable and economical methods available to remove undissolved solids from liquids. Expenditures of several million dollars have gone into the careful design of filtration equipment and proper selection of filter aids. New ideas and techniques are continuously being developed to aid adequately in insuring safe and trouble free underground injection.