Each year production is lost due to water influx from naturally occurring or induced channels or fractures. A special sealant process has been developed to help control subsurface water movement. The process consists of two individual states separated by a water spacer. Multiple treatments may be applied to control more severe downhole conditions. The first stage consists of about 200 gal/ft of a solids-free, non-Newtonian fluid with a viscosity of approximately 200 cp for matrix penetration. As much as ten pounds of solids per gallon may be added to this fluid for channels or fractures. This stage forms a very stiff gel when it contacts synthetic or formation brine. In fresh water zones where little salt is present, a preflush of concentrated brine is injected ahead of the first stage. The second stage consists of 10 to 30 sks/ft of low water-loss, accelerated cement slurry. This cement slurry is used to complete the special sealant process by forming a permanent, high-strength plug. To fit specific well conditions, solids may be added to the cement slurry. Successful sealant treatments have been performed in West Texas and New Mexico to correct subsurface water movement in producing wells. Most applications have been in naturally occurring or induced channels or fractures creating undesirable water flow. Sealant treatments up to 8,000 gal of first-stage fluid followed with 600 sacks of cement have been used.

Automating of oil production leases may be approached stepwise if proper planning is done initially. This paper summarizes the various automated processes in lease production, showing the limits and planning required to automate at each stage is set out.

Nitrogen alone has demonstrated success as a fracturing fluid in reservoirs normally found sensitive to liquid systems. It has proven useful in shales of the Ohio Valley and West Virginia areas, and in similar lithology of the Fort Worth Basin located in North Central Texas. The fracturing efficiency of nitrogen, as related to leakoff and flow capacity testing with no propping agent, has been investigated to analyze the effectiveness of nitrogen stimulation. Also, field data are presented which demonstrate successful results of the nitrogen technique in both oil and gas reservoirs. From the laboratory studies and field results, several conclusions were drawn concerning nitrogen stimulation. Of primary interest is that most of the width reduction in an unpropped fracture will occur in the early stage of production which indicates a sharp decline of the well flow rate after a relatively short period.

The effect of the physical properties of various cementing mixtures on bond log interpretations is presented. The nature of the pipe cement contact required for minimum acoustic transmission and effects of instrument calibration are also discussed.

The initial goal of a

A 12,500' hydraulic jet pumped well, located in Andrews County, Texas, was converted to a rod pumping system in order to reduce lifting costs and maximize profit. A rod pumping simulation program (wave equation) was used to quantify possible ranges of equipment loading, rod loading, plunger over-travel, and ultimately, production in the stock tank. The sucker rod pumping system design includes the use of fiberglass rods, a downhole separator located above a permanent packer and a tapered tubing string. The design criteria, installation procedure and actual system performance are presented.

The Snyder Field is located in southeast Howard County, approximately 15 miles southeast of (the City of Big Spring, Texas. The field was discovered in May, 1926, with the completion of the Magnolia Petroleum (Choate and Henshaw) No. 1, M. H. O"Daniel Well. The field covers 6000 productive acres and production is obtained from approximately 400 wells. The Snyder Field is south of the Iatan-East Howard Field and is separated from that field by an arbitrary dividing line utilized by the Texas Railroad Commission in distinguishing between the fields. The portion of the Snyder Field reviewed in this paper

The Northeast Jones area of Oklahoma was discovered in 1945. Production peaked in 1948 and the area was almost depleted by 1950. Primary recovery was an economic failure and the field was almost abandoned without a trial of secondary recovery. There were several reasons for the pessimism regarding water flooding, but the most predominant was the old "rule of thumb" that secondary recovery would be the same as primary recovery. The Northeast Jones Cleveland sand unit was formed in 1952, however, with the promotion of an outside group of operators. The water flood proved to be very successful and lucrative, recovering over twice as much waterflood oil as primary oil. Peripheral injection was employed which eliminated the need to drill new wells and, in retrospect, made the project much more successful than would a pattern water flood. The geometry of the water flood, the uniformity of the formation, and the high oil saturation are believed to be the major contributing factors to the high oil saturation are believed to be the major contributing factors to the high waterflood recovery and efficiency. Only 3.1 bbl of effective water injection were required for each barrel of oil recovered.

Currently available production packers are categorized according to function and design. A packer classification method is outlined with the equipment available from several manufacturers included as examples. Simplified cross-sectional drawings, photographic examples, major design features, and several common applications are included for each general type packer. An abbreviated packer designation method is also presented.

One of the first steps in determining how to manage a waste stream from a pipeline operation is to identify which regulatory agency has jurisdiction over the management of that waste stream. In the State of Texas, two state agencies and a federal agency have regulatory authority over different aspects of waste management. A lack of familiarity with current regulations may result in some confusion for pipeline operators. This was demonstrated in the last year.* It appears that many pipeline operators whose hazardous waste management activities are subject to RRC jurisdiction are actually registered through the Texas Natural Resources Conservation Commission (TNRCC). P The following discussion is intended to clarify jurisdictional issues with respect to waste management for pipeline operations in Texas and alleviate any potential confusion within the regulated community. This discussion does not address other issues, like pipeline safety regulation (RRC) or air emissions (TNRCC), where the jurisdictional boundaries are different than for waste. Jurisdictional authority for all regulated activities should be fully evaluated for each facility.

An 87-well lease in a major West Texas oil field has been converted to automatic operations except for custody transfer. The system automatically controls the production from the wells and the periodic well testing scheduled for the lease. All wells on the lease are pumped with standard, electrically powered, beam units. Periodic well testing, formerly done manually, is now performed automatically by means of electrically operated time controllers which divert on a pre-determined schedule production from the well to be tested through well test units. Lease production is gathered at a central storage battery equipped with automatic tank switching and safety controls. The pumper's work on the lease includes daily visits to the battery with the pipeline gauge to test manually the oil and to make the pipeline runs and checks of wells and equipment for routine maintenance.

Pressure coring offers a method for obtaining In Situ reservoir Saturations. However due to the requirement of pressure balance during coring it has henceforth been limited to use in reservoirs with pressure gradients greater than 0.25 psi per foot. This paper will describe techniques used to obtain the first known successful pressure cores taken using a foam mud system; thereby extending the useful range of pressure coring to under-pressured reservoirs. Stable foam is a compressable Non-Newtonian fluid that requires special design considerations when used in conjunction with pressure coring. Careful well design is necessary to insure Bottom hole pressure during drilling and coring operations does not fall below reservoir pressure. This can easily occur if foam degradation and nonlinear pressure gradients are not considered. A complete technique for using foam to pressure core, including well design, field implementation, and core handling is presented in this paper. This technique includes a well bore design, a pressure analysis method, a method of selecting optimal foam design, a description of logistics, an empirical calibration test, and a description of pressure coring operations and core handling.

The crude oil produced by ConocoPhillips in its South Guymon Unit is very paraffinic and has caused paraffin problems in formation, pumps, tubing, casing, flowlines and separators for years. Costs of production had been increasing because of lost production, plugged pumps, workover problems and stripping jobs. Many different types of treatments including cutting, solvent/chemical treatments, hot oil and hot water/chemical had been tried but all had been unable to reduce the problems or reduce costs. A unique application in this field has been found to cost effectively remove paraffin with cold water and chemical. This paper will discuss the application method, how it was tested and benefits resulting from its use.

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.