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.

In the past decade the number of secondary recovery projects has increased rapidly in the Permian Basin and surrounding area. Water injection is the most popular method of re-energizing reservoirs. As a result, demands on the artificial lift equipment have increased due to higher individual well productivity. In many instances larger equipment has been installed. Two major reasons for replacing beam equipment in the past have been torque limitations and displacement limitations. Torque limits are usually reached prematurely because the unit is being operated in the longest stroke. Displacement, limits are usually defined by an arbitrarily established maximum operating speed. As a result equipment is replaced when, with some modification, it could well have met the increased demands for a prolonged period. The slow, long-stroke pumping method is considered the best method for trouble-free operation of beam units. In the past, operators were able to employ this method because allowables were low and most fields were under primary recovery. As a result, lift equipment was not loaded. Now, with allowable factors up and secondary recovery projects responding, demands placed on lift equipment have increased significantly. Since producing wells are predominately equipped with beam units, ,any improvement in the loading efficiency of these units could result in substantial savings through delayed or unnecessary investment for larger units. One way to achieve this improvement is through the use of the fast, short-stroke pumping method, when applicable. Another way is by controlled overloading of existing equipment.

The necessity and desirability of well stimulation has been apparent for many years. Many wells and fields would not be economical producers without modern completion and stimulation methods. To break this situation down even further, it can be said that where several porous zones are present in a well, each zone will not contribute its maximum production without proper treatment. With these things in mind, our purpose becomes very clear. It is simply to properly stimulate each porous zone or stringer in the pay section. A number of methods have been employed to achieve this selectivity. Among these are packers, bridging plugs, straddle packers, and various forms of gels and other blocking materials. Tubing and packer methods are accompanied by reduced injection rates. Bridge plug methods require more time. Gel and blocking material methods are difficult to evaluate. Any of these approaches to selectivity involve considerable expense.

Pump design, material selection, and corrosion protection are presented as parameters in the selection of sub-surface pumps where pump usage is in a corrosive environment.

For CO2 flood modeling the complex geology at the Pennsylvanian SACROC Unit, new core was obtained by utilizing several new techniques to preserve key features or provide adequate detail on the analysis, including analysis of twelve-inch whole core samples. To maximize the value of new core data for model development and scale-up exercises, a "scale down" exercise was performed on selected samples: twelve inch whole core samples were analyzed then cut into six inch whole cores, two inch whole cores, and selectively plugged. Various analyses were run on each of the smaller steps to quantitatively evaluate the effects of sample size. This analysis shows Kv is sensitive to sample size, and smaller samples tend to overestimate Kv compared to their longer counterparts, especially in ranges less than 10 millidarcies. The modeling implication is that cores analyzed with standard methods may not adequately sample barriers to vertical flow.

Conventional downhole treatments for scale and corrosion typically rely upon either "squeeze" or batch type treatments for control of corrosion and/or scale. These treatments introduce large amounts of inhibitor into the wellbore area and may adversely affect the production characteristics of the well, require excessive amounts of chemical, and require repeated treatments over short periods of time. The use of encapsulated materials for scale and corrosion inhibition has recently been shown to be a reliable and economic alternative to the conventional squeeze or truck batch treatment. Encapsulated materials provide a reliable, long term, controlled release of inhibitor at concentration levels high enough to provide the required protection without introducing potentially damaging chemicals into the formation. This paper details field experiences with the encapsulated materials in a variety of wells and the results that have been obtained with these treatments.

A standard fracturing blender retrofitted with a microprocessor controlled proppant delivery system has been operating in the Odessa, Texas area since May 15, 1986. The speed and control capabilities of the system's microprocessor has allowed fracturing operations incorporating non-standard "ramping" sand concentration schedules to be routinely performed with this blender. Fracturing operations with "stair step" sand concentration schedules have also been completed with this blender. Subject paper presents a case history of fracturing operations performed in West Texas with a microprocessor controlled fracturing blender. Pre-job planning, system operation and blending capabilities of the blender are also discussed. Case history documentation for fracturing operations with ramping sand concentration schedules is presented in the form of strip chart data collected during these operations. Documentation is also presented for a fracturing operation with a stair step sand concentration schedule.