Many oil-producing areas suffer from troublesome paraffin deposition in production and transportation operations. The use of paraffin inhibitors, which are sometimes referred to as wax crystal modifiers or pour point depressants, have been effective at reducing plugging caused by paraffin deposition. To be effective these materials must be applied at a point before the paraffin falls out of solution and they must be present on a continuous basis. This presentation describes a technique for squeezing inhibitor into the reservoir rock matrix to get a slow consistent return of inhibitor provide an extended treatment for controlling deposition

In Coalbed Methane (CBM) production wells using Electric Submersible Pumps (ESP), it is common to control fluid levels to the required setting by the use of Variable Speed Drives. However this can cause high harmonics and, as a result, in the Powder River Basin in Wyoming, power companies have become increasingly reluctant to allow the use of variable speed drives and an alternative method of well control had to be found. A totally new approach to controlling ESPs, and thus the well fluid levels, was conceived. The Weatherford Well Management System0 (WMS) is a self-contained alternative to variable speed drives, which eliminates harmonics problems. It consists of a motor starter, a motor protection system and a microprocessor which controls a surface actuated choke in the flow line. During production operations, fluid levels can be controlled by automatically adjusting the choke. This paper describes the conception, development and field testing of the Weatherford WMS as a viable alternative to variable speed drives for downhole pump control. This system, which can be made compatible with any communication system, though designed for ESP applications in CBM production, is also applicable to other artificial lif t systems and oilfield applications.

Diversified efforts are continually being made to reduce artificial lift operating costs and/or increase oil production. The intent of these efforts is to put more profit in producing operations and prolong the economic life of present oil properties. Also, a greater ultimate recovery means more efficient use of our natural resources. Fluid Packed Pump has become a part of an artificial lift revolution with the development of the Unidraulic-a unitized, one-well hydraulic pumping system which can economically compete across the board with rod pumping equipment particularly in the larger sizes and in addition can offer several operating advantages. Let's face it, large volume lift is on the increase due to expanded secondary recovery operations, higher allowables and the desire to produce wells at their maximum capability rather than at a lesser volume due to inadequate lift equipment. The Unidraulic concept was discussed briefly in a paper which was presented at the 1971 Southwestern Petroleum Short Course. 1 It began taking shape in April, 1969, following the approval of development money, engineering time, and a testing program. The first unit was actually installed on a 5100-ft well in South Texas on January 20, 1970. There are now in excess of 50 Unidraulic installations throughout the Mid-Continent, West Texas, California and Hocky Mountain areas. The heart of the Unidraulic hydraulic pumping system is the power fluid conditioning unit which has been designed and assembled to provide a solid-free fluid which can be used to transmit horsepower hydraulically. Other required items of equipment are those normally associated with a central-battery installation-the surface wellhead control, the subsurface production unit and the associated accessory items.

Lack of submergence and gas interference are the principal causes of poor pump efficiency; both create fluid pound. Fluid pound contributes greatly to rod parts, bearing and gear failure in pumping units, V-belt failure and prime mover damage. The greatest loss is in production when gas interference is present. Subsurface gas separators of many designs are being used; these separators are essential. The more gas that is separated from the oil and permitted to escape up the casing before it can reach the pump intake, the better. Some of the gas that remains in solution until it reaches the pump intake will break out of solution as it passes through the dip tube and standing valve. Intermittent pumping will greatly reduce equipment damage where fluid pounds are created by lack of submergence. One can intermittently pump a well with gas interference and reduce damage to equipment, but often at a sacrifice in production. Much of the gas breaks out in the formation and enters the casing through the perforations as free gas. Free gas escapes up the casing at about six inches per second in oil, and this gas should not present a pumping problem unless the well is over-pumped or excessive back pressure is held on the casing. Some gas remains in solution until it enters the pump. Some gas remains in solution even through the pump. This gas breaks out when it reaches its bubble point and quite often flows off. This is called "heading up". Gas-locking occurs when the traveling valve remains closed throughout the stroke. The "Charger" valve supports the fluid load above the traveling valve until near the bottom of the downstroke, then charges the upper chamber with fluid. A fluid pound cannot exist unless the fluid load is supported by the traveling valve on the downstroke. A fluid pound on the upstroke cannot exist if the traveling valve supports the entire fluid load. With a "Charger" valve, the seal opens at the beginning of the upstroke because the pump is filled with liquid. The seal closes and supports the fluid load at the beginning of the downstroke. The upper chamber approaches zero psi quickly after the plunger starts its downward movement. The fluid and gases in the lower chamber simply pass through the traveling valve as it moves down. The fluid load is supported by the seal and the buoyant effect is eliminated permitting the rods to fall more freely, thus increasing the weight of the rods on the downstroke. In every test we have to date, the range of load in rods has been reduced because of this increased weight on the downstroke. The peak polished rod loads have remained about the same or have been reduced, except in one test where there was an increase, which will be discussed later.

With over 600,000 rod-pumped wells in North America alone, failure of this common artificial lift system substantially raises lifting costs. Among the leading causes of failure in sucker rod-pumped wells are rod parts and tubing wear. Typically, an operator has little reliable data with regard to tubing deviation and the root cause of rod-on-tubing wear and tubing or sucker rod failure. In many cases, a minority of wells constitute the majority of repeat failures and workover cost in a field. Obtaining tubing geometry, wall thickness and rod condition, correlated by depth, during the well workover is critical to determine the failure root cause. A system is presented that uses high resolution data and internet-based imaging of key producing well conditions to (i) enable efficient analysis and (ii) apply preventive measures before the workover is completed and the well returned to service. An application is launched from Internet Explorer that allows dynamic 3-D viewing of individual wells or entire producing fields. Tubing and rod geometry and condition by depth in the producing well, is downloaded to the client machine from a web server in compressed XML and then imaged in an interactive graphic format. Correlation of deviation, wear and failures is rapidly displayed in a 3-D image of a specific well or a field view. Cross-wellbore queries allow mapping of common well conditions. The net result is lowered failure frequency, lower lifting costs and increased annual production.

Optimum production of gas wells requires static and flowing pressure surveys to detect excessive liquid loading. Wireline pressure surveys have been customary in spite of their cost and potential safety risks. Developments in digital acoustic fluid level technology have resulted in being able to undertake not only static bottom hole pressure calculations from fluid level measurements but to extend this technology to flowing pressure gradient surveys in gas wells. The new procedure involves monitoring fluid level and pressure in the tubing during a short term test sequence. The procedure is inexpensive and non-intrusive. Tests clearly show the redistribution of flowing gas and liquid and allow the construction of the corresponding tubing pressure traverse and the determination of the flowing gas/liquid ratio, liquid fallback volume and flowing BHP. Examples of tests performed in operating gas wells that are flowing above or below critical flow rates are presented and discussed in detail.

A process is being developed to provide steel downhole tools and components with a proprietary Al2O3 based metalloid coating that appears to provide a barrier to hydrogen embrittlement and other corrosion forms. Laboratory tests of hardened steel specimens, stressed to 96% of the yield strength and complying with NACE TM-01-77 test requirements, resulted in "no 720 hour failures" or "indefinite time to failure" due to hydrogen embrittlement or sulfide stress cracking. Comparable specimens failed in less than five hours. Subsequently, coated high strength pony sucker rods were installed in West Texas wells with aggressive CO2 and H2S environments and pulled after a significant time period. This paper will provide a post-pull review of the condition of those pony rods relative to other sucker rods from the same wells. The coated pony rods performed without spalling or pitting while the uncoated rods showed heavy embrittlement and corrosion damage.

Abrasion and corrosion create costly problems in oil pumping wells. The cyclic action of the sucker rod string causes the rods, couplings and tubing to wear away. At the same time, they are being corroded away by the chemicals in the produced fluid. Eventually, the rods, couplings and tubing will fail and must be replaced. The resultant down-time to repair or replace the system is a great expense for the well operator.

The abrasive jetting technique consists of jetting high velocity streams of sand laden fluid from specially designed subsurface jet guns. These jet streams have the ability to perforate through casing and cement sheaths in a few minutes, and penetrate deeply into the formation behind.

A fully automated rod tong has been developed and deployed, which significantly improves well profitability by increasing mean time between failures of sucker rod connections. There is no other system available in the industry today that can automatically make sucker rod connections up to the manufactures" specifications. The rod connection service provides reliable, long term connection performance by controlling the CD to within manufacturers" specifications for every rod connection. The system also reports the true torque [ft-lb] in each connection, ensuring that proper lubrication and tightness have been achieved. The paper will show that controlling both CD and torque on makeup connections is the best way to ensure that proper preload of the pin is being achieved. This fully automated system eliminates the rod carding and tong calibration required by API 11BR recommended practice and the variations which can occur in the field due to uneven implementation of those methods.

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The Citronelle oil field, underlying the town of Citronelle, Alabama, is located on a topographic high approximately 350 feet above sea level (Figure 1). The existence of this surface anomaly encouraged oil and gas exploration in the Citronelle area. Oil was discovered in 1955 with the drilling of the Donovan Well #l on a vacant car lot. The discovery well flowed about 500 barrels of oil per day with an initial bottom hole pressure of 5000 psi. As discovery of the field continued, over 450 wells were drilled on 40-acre tracts covering about 17,600 acres. Cumulative production through 1997 was approximately 161 MMBO and 125 MMBW from the Citronelle field which is about half of the total oil produced in the State of Alabama. Oil production is currently averaging about 3300 barrels of oil per day with 10,000 barrels of associated saltwater production. Figure 2 reflects the historical oil production and water injection in the Citronelle oil field.

Since the popularization of oil well acidizing during the 1930's the specific problem of acid corrosion of tubular goods has been a fertile yet frustrating field for the corrosion chemist. Included in this paper will be a brief discussion of corrosion theory which will serve as a prelude to a discussion of more recent research developments which point to new parameters critical to the understanding and development of environmentally-acceptable organic acid corrosion inhibitors for the deeper and hotter wells of the 70"s. Also included will be a discussion of the various stop-gas measures that have evolved in an attempt to minimize the problems inherent with the common organic inhibitors. These techniques include: "double inhibiting", inhibitor slugs," inhibitor extenders or intensifiers, acid blends, sulfide control additives and inhibitor solubizers. The latest research developments in the areas of inhibitor-to-metal surface area ratios, acid turbulence, fluid cooling effects, and variations in grade grades of tubular goods will be presented as well as a description of the test apparatus and test procedures used in developing a new highly effective organic inhibitor.

Stimulation of carbonates with acid has been and will continue to be one of the most economical means of improving the performance of both production wells and injection wells. Performance improvement is accomplished through the proper match-up of fluids and techniques to the reservoir The beginning of a successful stimulation starts with an understanding of the reservoir composition and pore system. Having defined these reservoir properties, an evaluation of fluids which will not only achieve the best differential etching in the carbonate but will also maintain rock integrity to withstand closure of conductivity pathways created by acidization comes next. Lastly, control of leak-off and reactivity for placement to insure deepest penetration and conductivity is considered. Presented are examples of implementation of the above evaluations, which have resulted in successful stimulations. These case histories cover a wide range of reservoir conditions and geographical areas.

One of the most effective methods of carbonate stimulation is acid fracturing. Development of fracture geometry sufficient to allow etched penetration to provide economic production increases is dependent upon several factors, one of which is pump rate. High rates and/or lower hydraulic horsepower requirements can be critical to success to one of these projects. Many times wells lack the integrity or flexibility to be treated down casing. Treating down tubing affords highly viscous fluid's opportunity for rate restrictions due friction pressure. In addition, fluids of high viscosity based on the crosslinking of polymers using zirconium are known to have shear limitations, and, therefore, high rates have been unattainable. Laboratory testing and case histories are presented regarding the evaluation and usage of zirconium crosslinked hydrochloric acid systems in the acid fracturing of several carbonates utilizing a variety of tubulars from 2-3/8 to 4-1/2 inch.

Mud solids can cause severe productivity impairment which can only be prevented by the use of acid-soluble muds. Conditions justifying the use of such muds are as follows: 1) Highly permeable formations (say above 500 md). 2) Carbonate reservoirs of low matrix permeability whose productivity depends on a fracture network. 3) In production repair wells where the risk of lost circulation into depleted reservoirs and of plugging established flow channels is high. 4) When it is advantageous to have an acid-soluble filter cake, e.g. when gravel packing, shot perforating, or if a good cement bond is required. Acid soluble, water-base fluids are composed of graded carbonate bridging particles whose maximum size must be equal to at least one third the largest expected pore opening. Filter loss control is best provided by an acid-soluble lignosulfonate and viscosity by hydroxyethyl-cellulose. Sodium chloride or calcium chloride brines and/or ground carbonates (44-2 microns) are used then higher weights are required. One type of acid-soluble oil-base fluid is an invert emulsion stabilized by treated carbonate fines. In others an oil-soluble colloid is used. In both cases ground carbonates are used for bridging and weighting. One problem that arises when drilling with acid-soluble fluids is the incorporation of insoluble drilled solids. This is minimized by not introducing the fluid until the top of the productive horizon is reached and by the greatest possible use of mechanical separation equipment. In production workover jobs, the most common problem is loss of circulation. To prevent or remedy this, the fluid is applied as a pill containing a high concentration of bridging solids.

This paper explains a new approach in choosing the most acceptable treating fluid and a history of field applications using the new method.

Acoustic instruments have been used routinely for many years as an aid in analyzing well performance of normal-pressure oil producers. Recent developments in equipment and techniques now permit more-accurate calculations of acoustic static bottomhole pressures at surface pressures up to 15,000 psi in corrosive (COP and H2S) environments. Equations and charts are presented herein for determining static bottomhole pressures from acoustic and well data. Also, a special technique is recommended for shutting-in a well which in most cases will yield more-accurate results. The bottomhole pressure of wells producing high concentrations of CO, gas can be determined from acoustic data and the tables and figures given herein. This method has been programmed for an inexpensive, portable notebook-size computer which can be used in the field to easily perform these calculations.

The ACE log is an efficient aid in determining the quality of reservoir isolation achieved through primary or squeeze cementing. A subject of controversy since its inception, cement bond evaluation has improved with advanced technology and with continued concern by the industry for an effective evaluation meth0d.l A better understanding of the operations principles by service company and operations personnel, meaningful calibration, and the application of logic to interpretation are some of the factors responsible for increased acceptance by the industry. Properly run ACE logs respond to downhole conditions that are present, which may or may not correspond to the expected conditions. Unlike formation evaluation logs, there are no correlative factors extending from well to well to act as repeatability checks. Each log must stand on its own, and its interpretation must be supported with logic. The lack of standardization of logging systems by service companies should not present an insurmountable problem to log quality or interpretation if proper basic logging principles are followed.

Electronic equipment is available to determine the fluid depth in oil wells quickly and accurately. The fluid depth is determined by producing a sound wave at the surface and recording the reflections on a strip chart. Therefore, the instrument is called an acoustical well sounder (AWS). The most common means of producing the sound waves is by firing a black powder blank into the annulus. Recent innovations of gas guns have improved the safety and performance, and decreased the cost of using as AWS. The acoustical well sounder is primarily used to determine producing fluid levels, shut-in levels, and fluid build-up curves of an oil well.

The Coalbed Natural Gas Industry, or Coalbed Methane (CBM) continues to gain global popularity and momentum. However today, CBM operations are one of economic challenges. Varying coal seam depths, rapidly declining water production rates, uncharacteristic well completions, sand, coal fines, etc., prohibit using just one form artificial lift equipment. Successful CBM production operations demand multiple product lines. Weatherford determined that a new approach was needed that offered multiple product lines in addition to modifications of conventional artificial lift products. A presentation will be prepared that outlines the challenges CBM production presents to operators. This paper and presentation will discuss old artificial production techniques and new approaches. Because there is a never-ending focus on lowering lease operating expenses (LOE) operators continue to push manufacturers into modifying and or developing new production products. Weatherford has a dedicated CBM team determined to lead the industry in CBM equipment development. This paper will offer some of Weatherford's solutions to this ever-demanding industry.

The Adjustable Valve Rod and Pull Tube Guide is designed to allow for precise spacing in a down-hole sucker rod pump. In historical installations the spacing is based on the valve rod or pull tube length. This length is usually in one inch increments from the factory, or the rod or tube is field cut and threaded to maximize the pump compression ratio. This patented guide allows the spacing to be adjusted with greater precision and will compensate for manufacturing tolerances and reduce field cutting and threading of pull rods and pull tubes. This paper will describe how the guide is designed, its specific applications and its advantages over conventional sucker rod and pull tube guides.

Virtually every oil production company and many gas producers, both major and independent, must use one or more forms of artificial lift to assist in producing their wells. Yet, most companies do not have artificial lift experts. In fact, many companies don"t even have engineers trained in artificial lift. And almost no companies have artificial lift research and development programs. In fact, most companies must depend solely on the service companies to provide the artificial lift technology, products, and services they require. But, all production companies face many challenges in the artificial lift arena to optimize the economic recovery of their hydrocarbon (both oil and gas) reserves. This is certainly true in the "green" field areas of horizontal, multi-lateral, deepwater, and sub-sea wells, and wells in challenging locations such as deserts, arctic environments, etc. It is also true in "brown" fields where even small percentage improvements in artificial lift effectiveness and efficiency can make the difference between a profitable and an unprofitable operation. If artificial lift is so important, and if "getting it right" is worth so much, why is there so little engineering focus on it? The answer seems to be that many companies consider artificial lift to be "old, existing, proven" technology, with little or no room for improvement. Many people feel that pumping or gas-lift is relatively simple. If the pump is going up and down, the well must be producing oil. If gas is being injected into the well, it must be producing by gas-lift. While these "feelings" may be true to some extent, it is often (perhaps normally) the case that the artificially lifted wells that do not receive much attention are operating very ineffectively and inefficiently. They are producing much less than they could; they are costing much more to operate than they should; and often both capital and repair and maintenance costs are much higher than necessary. This is not an idle claim. It has been proven, time and again, that an effective artificial lift surveillance program and application of appropriate artificial lift equipment and practices, can significantly increase production, reduce operating costs, reduce repair and maintenance costs, and often reduce capital expenditures. It has been proven that use of effective artificial lift processes, equipment, and practices can result in: Beam pumping wells - 5 - 10% more oil - 15 - 20% less energy consumption - 25 - 35% reduction in repair and maintenance costs Gas-lift wells - 5 - 10% more oil - 5 - 10% less gas-lift gas - Lower investments in compression equipment Electrical submersible pumping wells - 3 - 5% more oil - 6 - 12 months longer run times Being realistic, this is not a "pitch" to have every oil and gas production company hire an artificial lift engineering staff or start an artificial lift R&D department. Realizing that this is not going to happen, there is currently an effort underway to form an industry-wide organization to focus specifically on advancing the technology and "business" benefits of artificial lift by enhancing artificial lift technology, understanding, training, processes, equipment, practices, and applications. This industry initiative is called the Artificial Lift Research and Development Council (ALRDC).

"The Wellhead Scanalog is a new and effective approach to the evaluation of used oil field tubing. Designed to perform tubular inspection while the tubing is being pulled, it does not interfere with normal workover operations. The tool provides four non-destructive methods to detect and evaluate used tubing defects such as rodwear, corrosion pitting, erosion, holes, and splits. A new rotating magnetic field technique is used for rod wear, a modified flux leakage technique is used for pitting, and average wall measurements derive from a total flux concept. Eddy currents are used for holes and splits. Radiation techniques are not used for safety reasons. Sensing systems are non-contract, and not affected by scale, mud, paraffin and water, and there are no active or moving parts in the sensor package. The tool bolts directly onto the well head, and in many fields several wells can be inspected each day. Sequential inspection of tubes in over 5000 wells inspected has revealed well tubing profiles which provide useful diagnostic information for well servicing programmes."

The use of Variable Speed Drives to control Rod Pumps has been tried with varying results. The success has been limited due to issues such as surface equipment reliability, regeneration, voltage and current harmonics, poor power factor, and premature Rod, Tubing, and Pump failure. This paper describes a unique technology that combines the latest advances in power electronics with patented firmware and application software solutions resulting in optimized production and reduced maintenance and energy costs for heavy oil, high gas content and "problem" wells. The technology eliminates pump-off and allows the operator to maintain the fluid level at a predefined level above the pump, maximizing pump fillage, while accurately controlling the rod speed at all times preventing premature rod failure. This new technology also produces a near unity power factor and a minimum of voltage and current harmonics and allows the use of more cost efficient high efficiency NEMA B motors.