This paper will cover common problems and misunderstandings that lead to sucker rod pumped well failures and some of the solutions to avoid failures and optimize the sucker rod pump system.The mechanics of the sucker rod pump design and modifications to improve performance in harsh well environments and failure data collection and performance measurement will also be examined.

Multi-component, pliable plugging agents used to combat lost circulation are well known in the drilling industry. The role of these materials is to provide wellbore pressure containment and to allow for drilling ahead by sealing thief zones and stopping drilling fluid losses. This paper presents a unique method to model and quantify the optimal downhole mixing energy for multi-component, squeezable plugging agents. Understanding and controlling the mixing energy involved in placing these types of treatments is vital for success. The application of engineering similitude and a proprietary laboratory method is used to create a model that transforms bench-top mechanical mixing into forecasted downhole mixing at the drill bit. A custom-built apparatus that simulates specific downhole mixing and placement is used to confirm the optimal operating conditions projected from the similitude model and bench-top tests. Results for various chemical treatments are validated in this work.

This paper will focus primarily on damage to sucker rod pumps and other parts of the sucker rod pumping system due to common mistakes in operation procedures and operating conditions. A review of actual damaged materials and the operating parameters leading to the root cause of the failures will be presented as well as the solutions that were implemented to solve the problems.

Recent estimates indicate that oil producers will spend about $750 million in 1977 to replace tubing rods, pumps, etc. because of corrosion. While down time caused by the need to replace corroded equipment will not necessarily result in permanent loss of production, it certainly does result in lack of ability to produce oil now when we need it. To compound the problem, we will also import more than 40 percent of our petroleum needs in 1977. Thus, in addition to the out-of-pocket costs of replacements, oil producers also suffer from reduced income when wells are not producing. An obvious remedy is to prevent the corrosion. Not so obvious is how. Using corrosion-resistant materials is one approach, but the expense of exotic metals could exceed the cost of replacing conventional corroded equipment. Proper design can reduce corrosion, and corrosion allowance can be included in the design. Neither is totally satisfactory, but each will extend the time before replacement will be required. Production practices such as slowing pumping rates to reduce rod stress and complete exclusion of oxygen in annular spaces, especially wells with low fluid levels, help alleviate corrosion problems. Since the combined effects of corrosion and wear are greater than just the sum of both if each occurs alone, rubbing parts (rods and tubing) and solids entrained in fluids should be avoided. Corrosion can also be slowed by changing the corrosivity of the fluids by removing corrodents (H2S, CO2 or oxygen) or by altering the pH. Sometimes one or more of these can reduce corrosion to acceptable levels. Where they will not, corrosion inhibitors are used. For optimum effect (lowest cost) corrosion inhibitors have been developed to exhibit a wide variety of properties that enable them to prevent corrosion under a variety of production practices and equipment configurations. Corrosion inhibitors that are used to prevent corrosion in rod-type oil wells do so by adsorbing onto metal or metallic corrosion products such as iron sulfides, carbonates, oxides, and scales. They can prevent corrosion when as little as a monolayer of inhibitor molecules are adsorbed on the surfaces that would otherwise be exposed to the water that is necessary for corrosion reactions to proceed. In essence, one end of the inhibitor molecule adsorbs and the other end sticks out from the surface to repel the water. There are several important fundamental aspects of chemistry and physics that determine both the rates of adsorption and the quantities adsorbed. Second, there are also several important characteristics of inhibitor mixtures that influence these functions. And third, there are several physical factors related to equipment, production practice, and variables in the corrosive environment itself that affect the adsorption and subsequent corrosion protection.

This paper reviews material and installation requirements for water-handling systems from the standpoint of general design, suitable materials and potential problem sources in the closed type system.

All the advancements in metallurgy, improvements in manufacturing technique, and refinements in design that go into the building of the modern pumping unit are without value if that equipment is not operated correctly. Upon the operating personnel of the oil industry falls the responsibility for correct operation of pumping equipment.

This paper discusses factors controlling production from a well and deals with using liquid level instruments to obtain down-hole information from which production efficiency can be determined. The effect of casing pressure and high liquid levels on production rate is given in detail. Also good production practices are offered, involving such subjects as proper casing pressure and pump setting depth. Data is given to simplify obtaining down-hole well bore pressures from surface data.

Many gas wells produce water or a liquid hydrocarbon or a combination of the two. Often, the velocity of the produced gas is not sufficient to lift these liquids to surface and they accumulate downhole and decrease the well's gas production by applying pressure against the producing formation(s). One way to prevent this decrease in production is to apply a deliquification surfactant downhole. Very simply, these surfactants facilitate entrainment of the gas in the liquid phases, allowing the gas / fluid mixture to be lifted to surface with the existing velocity. Many surfactants work in water-only fluids or in hydrocarbon-only fluids, but most products fail to perform when the liquid hydrocarbons and water are near equal ratios. This paper will illustrate the laboratory work and successful field application of several specialty surfactants designed to handle a wide range of oil/water ratios, including equal mixtures of the two.

Maintaining low operating costs is a critical aspect of field operations. This is a sizable challenge when producing deep, high volume, high water cut wells in a mature oil field. Profits from such wells are usually marginal and heavily dependent on oil prices due to somewhat fixed operating costs. West Texas is home to many wells that meet these criteria. Most are produced with hydraulic jet pump systems or. More commonly, submersible pump systems. Both systems are reliable and each offers advantages. Both systems are also renowned for high electrical consumption: an attribute not welcomed m today's efficiency-focused environment. Hydraulically operated reciprocating pump systems have been used in the oil field since the mid 1930"s. Despite lower daily operating costs this system is not as common due to shorter pump run life and high equipment surveillance demands. One manufacturer made maJor modifications to the pump improving the pump's overall performance and significantly increased the volume capacity. This type of pump offers several advantages and is extremely competitive with other high volume lift systems. This paper summarizes the results of seven hydraulically operated reciprocating installations in the Mobil operated Russell field. The systems are installed in wells producing from 2.50 bfpd to 1650 bfpd from depths a great as 10,700 feet. Current data indicates that 20 to 40 percent less horsepower is consumed, compared to other systems. Consequently, profit from each barrel of oil produced increases. The pump also operates at lower producing bottom hole pressures compared to jet pump systems resulting in higher production rates. The advantages and disadvantages of the reciprocating pump are presented.

Present day technology allows maximum sucker rod loading to be 50,000 psi, and air balance pumping units are available with stroke lengths of 240 inches, beam capacities of 47,000 pounds and gear reducers that have a torque capacity of 2,56O,OOO inch-pounds. Sucker rods with a diameter of 1.125 inches are available. A.F.I. RP 11L supplies data on 1.25 inch rods, but these are not manufactured at this time.

The Petroleum Industry is becoming more aware of the significance of rod string side loading and associated tubing wear. This wear is due to rod string buckling resulting from down-stroke compression and/or wellbore deviation. Rod string couplings are an integral part of rod string design. Proper selection and installation is critical since these couplings connect every design element in a rod string and can dictate well performance and economics. During lift operations, rod couplings can experience compression and side loading. The result is contact with the interior surface of production tubing and coupling on tubing wear. Results from this paper will provide the Petroleum Industry with a more accurate understanding of reciprocating rod coupling on tubing wear. This wear test utilized the following parameters: * 2-7/8", J-55, ERW tubing * 7/8" Spray metal and Class "T" rod couplings * Water/glycol fluid media * Side load of 57 lbs. A better understanding of rod coupling on tubing wear will provide the Industry with improved sucker rod string design guidelines. Use of these guidelines will reduce costly coupling on tubing wear and resultant failures that impact the ability of the Petroleum Industry to economically produce oil and gas.

The Petroleum Industry has been aware of rod string and tubing wear ever since the first installation of steel sucker rods in production tubing. The associated rod string and tubing wear from this lift system continues to impact the ability of the Industry to economically produce oil and gas. The downstroke phenomenon of sucker rod string compression, buckling, sucker rod and tubing contact and associated sucker rod and tubing wear is becoming more clearly defined. (1,2,3) This paper will provide the Petroleum Industry with a more accurate understanding of sucker rod and tubing wear resulting from sucker rod side loading initiated by downstroke sucker rod buckling. This paper will present a description of test equipment and test parameters resulting in the following; 1. Calculated cycles to 100% tubing wall loss vs. side loading. 2. Calculated cycles to 100% sucker rod diameter loss vs. side loading. 3. Calculated cycles to 100% sinkerbar diameter loss vs. side loading. A better understanding of sucker rod and tubing wear will provide the Industry with better sucker rod string design guidelines. Use of these guidelines can reduce costly sucker rod and tubing wear and failures that impact the ability of the Petroleum Industry to economically produce oil and gas.

A new computerized fluid level measurement method is described. Instead of using the traditional gas gun and microphone system, a transient wave is created by venting a small amount of gas from the casing and the fluid level is located with help of an ordinary pressure transducer. The method measures acoustic velocity of well gas external to the well in a known length of coiled tubing. This eliminates the need to count tubing collars to determine velocity. Much of the equipment is off-the-shelf, and cost is less than with traditional systems. Results from field measurements show that the new method provides accuracy which is comparable to traditional systems. The new technique presents an uncluttered result without electrical or digital filtering which clearly shows the fluid level in the majority of cases. The simplicity of the return echo helps differentiate other objects and conditions that might pose as fluid level such as uphole leaks, liner tops, and tubing anchors. The paper discusses many practical applications of the technique in locating fluid levels. It also describes how CO2 movement within the reservoir can be tracked as a by-product of measuring fluid levels. The paper also illustrates how the wave equation can be used to explain various fluid level echoes encountered in the field.

Analysis of Nolte Plots, the log of net fracture pressure versus log of time, can be useful in hydraulic fracturing stimulation treatments. Trends and characteristics of the formation established by these plots are being evaluated and used in an effort to optimize subsequent treatment design. This paper will present case histories on wells in the Turner formation in the Finn-Shurley field of Weston County, Wyoming and show how continuous measurement while fracturing is a useful tool in optimizing future job design.

This paper outlines some of the economic factors to be considered in the chemical treatment of oil and gas wells for corrosion control. It also presents several advantages and disadvantages of some mechanical application equipment and the economics involved in using the equipment. The paper also describes and evaluates several chemical applicators which are economical to use.

The Federal Government released a new requirement under the Occupational Safety and Health Administration Standards on May 26, 1992. This code for process safety management was issued under 29 CFR 1910.119 in the Federal Register. The code contains requirements for preventing or minimizing the probability and consequences of catastrophic releases of toxic, flammable or explosive chemicals. Oil production and processing facilities which have processes involving more than 10,000 lbs of flammable liquids or gases and which are "normally manned" are covered under this code. Under Section J of the code, employers shall develop written procedures to maintain the on-going integrity of pressure vessels, tanks, piping systems, vent and relief systems, pumps, controls and emergency shutdown systems. Employers are also required to document that tests and inspections are consistent with applicable manufacturers" recommendations, industry codes and practices, and that they have actually been performed. ARC0 Oil and Gas Company has spent a significant amount of time and resources developing programs to be in compliance with this code. One such program involves determining and documenting the mechanical integrity of pressure vessels. Prior to the 1930's pressure vessels were typically constructed to the purchaser's specifications. At that time a code was developed to cover standard construction of unfired pressure vessels. This code, the API/AWE Code for Untired Pressure Vessels for Petroleum Liquids and Gases, was the standard construction code in the petroleum industry until January 1, 1957. At that time, the ASME Section VIII code was developed to cover design, fabrication and inspection of pressure vessels. Most pressure vessels in the petroleum industry which were constructed after 1956 were constructed under ASME Section VIII, Division 1. There are basically two recognized codes covering the inspection of pressure vessels. One code, the National Board Boiler and Pressure Vessel Inspection Code, NB 23 is often used in chemical plants and refineries. It is also used by companies which have registered with the National Board as Owner/User groups. Another code which is available for use is API 5 10 - Pressure Vessel Inspection Code. ARC0 Oil and Gas Company has chosen to use the API code for inspections of pressure vessels. API 5 10 has two specific sections covering inspection and testing of pressure vessels. Section 4 covers all pressure vessels except those used in natural resource service. Under API 510 Section 6 - Alternative Rules for Natural Resource Vessels, owner-user field establishments involved in drilling, production, gathering, transportation, lease processing and treatment of liquid petroleum, natural gas, and associated salt water (brine) may elect to use an alternative set of inspection rules. The only stipulation for this section is that any organization which decides to use this set of alternative rules should apply them to all vessels in that field or service environment. ARC0 Oil and Gas Company has elected to use Section 6 for all field and plant pressure vessels. API Section 6 allows vessels in common circumstances of service and pressure in a field environment to be grouped together as a "class of vessels". This allows inspections to be grouped by class and scheduled over a longer time period on lower risk vessels. ARC0 has elected to use common class of vessels to group similar vessels on non-OSHA 19 10.119 B and C Class facilities.

Contrary to present-day methods, this machine operates a sucker rod system at a constant velocity through approximately 80 per cent of the stroking cycle, the balance of the cycle being used to halt the motion and reverse the direction. The reversal action of this machine is accomplished with out the aid of power. To effect the reversal, it utilizes some of the energy put into the system during the constant velocity portion of the stroke. The method of accomplishing this non-power reversal will be fully explained as well as all other engineering features of the equipment. A portion of the paper will deal with the mathematical formulae used to size the equipment for a given set of conditions and what the expected production would be. Also included will be the operating methods and maintenance requirements as well as detailed field performance figures

Conoco trains engineers and waterflood operators in their on-going waterflood school. It is in this school that waterflood problems are presented and resolved. This presentation concentrates on waterflood operational problems, discussed in this school, such as: preventive maintenance, problem producing wells, flowline problems, corrosion, tubing, polished rods, casing, produced water clean-up, waterflood station vessels, and injection pumps and meters.

This paper deals with the development of a mathematical model to describe the miscible displacement of drilling muds by cement slurries under laminar flow conditions. The model accounts for the effects of differing properties, geometry, and displacement rates. The model assumes that "mixing" in the displacement zone by molecular diffusion is minimal, and uses the Robertson-Stiff model to describe the rheological properties of both the drilling fluid and the cement slurry. The application of the model to a range of displacement conditions (densities, viscosities, yield stresses, displacement rates, etc.) indicates the conditions under which optimal or near optimal displacements are possible, and hence, provides a basis for designing efficient cementing operations from simple material property characterizations. Of special interest is the effect of the yield stress. These parameters are founded to strongly affect the displacement efficiency, particularly the formation of cement channels. Such results are described quantitatively in the paper. The effects of the other rheological properties, the densities, and the displacement rates are also described. Field application cases are also included in this paper.

The prime consideration of an operator after the pumping unit has been installed is how to obtain the longest possible operating life, the minimum amount of nonproductive time, and the lowest overall operating cost. This problem is most easily solved by an understanding of the basic operation of the unit and the requirements of maintenance.

Although membrane separation is perceived as new technology, membrane based CO, removal has been commercially practiced for more than 15 years. The first commercial membrane based CO, removai system was the SACROC facility in west Texas. The system was commissioned in 1983. Over several expansions, the capacity of the facility has quadrupled and continues to provide a cost effective solution. This installation represents a true success story for membranes. Slowly but surely, membranes are becoming the preferred technology for CO, recovery in EOR applications and for bulk removal of CO, for offshore natural gas treating,. This is largely because of their operational simplicity, lower capital cost, and environmental benefits relative to competitive technologies for acid gas removal.

Stuffing boxes on beam pumped wells have always required a high level of maintenance even though operators and manufacturers have constantly searched for ways to improve their performance. Essentially no documented research has been developed on which to base performance enhancing designs. It is the purpose of this paper to offer two new concepts which could benefit stui"fing box performance. Steel and rubber are known to be among the worst combinations of materials for applications where a low coefficient of friction is important. Therefore, the first concept is the introduction of a new friction reducing process which improves compatibility of steel polished rods and rubber packing. The second concept is the introduction of laboratory test equipment which can be used to objectively shed new light on stuffing box designs. Because the coefficient of friction between rubber packing and the polished rod is one of many design variables that is important, the test equipment was used to measure this frictional effect as the starting point of a research project to improve stuffing boxes overall. The information presented in this paper is only a start. It's not absolutely conclusive regarding the merits of either the new stuffing box packing or the laboratory equipment. But the results are exciting and suggest significant improvements to stuffing box performance may be in the offing.

First, we have established that it is a necessity to meter fluids if we are to transfer fluids to their eventual consumer, so it makes little difference here whether this phase of metering is profitable or not. The only question here is one of method. That is, which method is the least expensive and results in the least waste. This is the argument now in question concerning lease automatic custody transfer and conventional crude handling facilities.

A study of stimulation techniques in the Morrow and Atoka formations was conducted because operators wanted to find a way to slow the anomalous decline in production from wells that were drilled and completed during the late 1970s and early 1980s. Operators investigated completion practices used during this period and conducted pressure-transient analysis. They analyzed sidewall cores for mineralogy studies of the reservoir rock and sensitivity testing of water and acids. From this study, we concluded that the completion fluids used were damaging the reservoir rock. Buildup analysis showed that most fracture treatments only reduced the positive skin present and rarely resulted in stimulation. This study revealed the need for a nondamaging fracturing fluid that would improve the success of fracture stimulation in the Morrow and Atoka formations. A foamed methanol system was developed to address the high clay content and water sensitivity of these formations. The paper presents the rheological, fluid-loss, and friction properties of the fluid system. Since the introduction of this system, more than 100 successful treatments have been pumped with favorable results. Case histories of both low-pressure and high-pressure zone completions are presented.

Paper addresses conformance problems with dominating eroded interwell communications to offset producers in certain patterns of the SACROC Unit Carbon Dioxide Enhanced Oil Recovery (CO2 EOR) Project in Scurry County, Texas. The opportunity to maintain optimum pressure support and desired mobility of the hydrocarbons in various patterns and areas was being lost. Various technologies and methods were investigated and/or deployed in attempts to redistribute CO2 injection into desired intervals and reduce the wasted cycling. The injection wells have and will be treated with solutions capable of modifying fluid flow in an extended reach away from the near-wellbore. Applied diagnostics provided guidance for the designed remediations of the communication problems. Criteria were then established for the physical and chemical attributes needed by the conformance solutions group to address the identified problems. Illustrated are problem identification diagnostics, selection processes for solution attributes and capabilities, and placement control requirements.