With the use of invert emulsion fluids, environmental responsibility has increased the cost and liability associated with the disposal of contaminated drill cuttings. In environmentally sensitive areas it is unlikely that any discharges of contaminated cuttings will be permitted and responsible treatment methods must be found to minimize future liability. Development of an invert emulsion drilling fluid designed for both the high performance drilling and optimized treatment of contaminated cuttings has been a key in minimizing environmental impact. Developing efficient treatment techniques for the local environment has been equally as important. True environmental responsibility has been achieved by combining chemistry and treatments to produce an end product which can be beneficially re-used in the local environment. The Authors will discuss the drilling fluid chemistry and treatment techniques, will show the field performance of these fluids, and will review the potential for beneficial Reuse of contaminated cuttings in this context and show results of field trials.

Drilling is required for the exploration and production of almost all forms of energy and mineral resources found in the earth. Current drilling activity in this country is large and working near the industrial capacity. For example, the petroleum industry alone drilled approximately 145 million feet of hole in 1974 at an average cost of $24 per foot. The uranium industry drilled an additional 22 million feet to bring the total drilling cost to almost $4 billion in 1974. This figure was exceeded in 1975 and projections for 1976 are higher still. Using today's rotary technology, the cost of drilling for petroleum increases exponentially with hole depth as shown in Fig. I. The future development of geothermal resources will pose even more severe problems to the drilling industry. The more competent basement rocks at elevated temperatures are more difficult to drill, and footage costs are factors of two to four higher than for comparable depth sedimentary drilling. If improved drilling technology is not developed, this expense, coupled with the shortage of rigs and trained crews, could severely limit the timely development of this resource. Drilling technology could become a limiting factor in future energy development if ways are not found to increase the footage drilled and reduce the costs per foot. Significantly increasing the active rig count does not seem to be a viable option due to the very long lead time associated with new rig deliveries and the severe shortage of trained personnel.

Before 1950, drilling strings contained few drill collars, and the hole depth was shallow enough so that grade-E drill pipe easily satisfied most requirements for drilling and drill-stem testing. In 1957, when Great Western Drilling Company drilled the Phillips Petroleum Company Montgomery A-l to 23,400 feet, engineered drilling strings became necessary. Between 1957 and the time the API published RP7G, drilling-string design was a daily necessity for drilling engineers to avoid operational problems and to satisfy contractural requirements. Each engineer designed his drilling strings based on his knowledge and training, and the procedures were based on techniques previously used in the design of casing. In the vacuum created by operational necessity and the lack of API recommended practice we developed a philosophy and two report forms for our use which have worked well. Examples of the use of these report forms and a comparison between our philosophy and the API RP7G recommended approach are presented in this paper.

This paper presents a case history of the methods used by Exxon co., U.S.A. to drill the St. Lawrence Field in Glasscock County, Texas. Lightweight oil base mud was used to combat salt and lost circulation, while brine water weighted with hematite was used to drill an abnormally pressured section. Two-stage and tack-and-squeeze cementing were used to place cement across lost circulation zones. The lightweight oil base mud was technically successful, yet proved uneconomical. In contrast, the hematite was cost effective as a weighting material. The tack-and-squeeze method proved to be the most successful method of cementing.

In 1982 the Employment and Productivity Sub-Committee of the U.S. Senate Committee on Labor and Human Resources held a series of four hearings on United State's productivity performance. Testimony was heard from witnesses representing education, science, industry, high technology, labor and government. During those hearings, information surfaced that was serious enough to warrant holding a fifth hearing. Seventy bit lion dollars down the drain. Think about it. According to the Sub-Committee's findings, seventy billion dollars is how much money American business loses annually because of alcohol and drug abuse by employees. Not possible? Consider---A business climate with decreased productivity, unmet quotas, absenteeism, tardiness, and couple that with an increase in security problems, accidents on the job, and destruction and theft of company property. Get the picture? It doesn"t take a computer analyst. from California, or a financial expert on Wall Street to spell it out for you. Pot., pills, powders and booze...sapping the strength and drive of America's work force. These impaired workers function at slightly more than half their normal capacity. With three million alcoholics in the United States and up to fifty-three million people using drugs occasionally, we are looking at almost sixty million workers performing at significantly less than their normal capacity daily.

DTS sensing is an emerging technology in which a local operator used on 16 wells to determine the effectiveness of acid treatments. The technology uses a fiber optic cable to read temperature realtime downhole per foot along the wellbore. This allows the service company to validate fluid placement. The effectiveness of the acid treatment can now be determined. Effectiveness can also be determined by how much improvement in production takes place after the job. In the case studies observed, effectiveness was determined during the pumping of the job with DTS sensing rigged up to the well. It is this configuration that an operator can decide if a change to the design should be made, real time-during pumping. The effectiveness of an acid job is dictated by effective fluid placement. One wants to know where the acid was placed in the well. Does all the acid go where it is supposed to go, in each zone? Or, does a high percentage of the acid go into the first least resistive zone and subsequent zones go untreated. If the latter takes place, a portion of investment capital used on gallons of acid will be wasted. Acid treatments can include a wide variation of stimulation methods or processes to improve the effectiveness of the treatment. These processes include stimulating the formation using fracturing or matrix rates, varying the acid percentage, varying the type of acid, using linear, gelled or crosslinked acid, varying the rate at which acid is pumped, and using particulate and chemical diverters. Previously on acid jobs, surface readings for pressure and rate were the only indicators to judge the effectiveness of the treatment. The legitimacy of this type of interpretation can be questioned because friction pressure encountered can mask what is actually taking place downhole. As the operator attempted all the above acid treatments and also monitored treatment with DTS, it was revealed that what we see at the surface can be misleading.

The term "dual completion" refers to a method of producing two zones through the same well bore without co-mingling of fluids. A dual completion is one that promises greater economy. During recent years the percentage of such completions has been greatly accelerated, due to mounting development costs. Because of the success of dual completions, and the favorable economic aspect, there is no reason to predict a downward trend. Equipment manufacturers are constantly redesigning and improving their equipment to meet the demands of equipment applications. The purpose of this paper is to discuss various types of dual completion installations, beginning with the very basic type and progressing to the later types, which are becoming more commonly used.

The need to produce large volumes of fluids from secondary recovery wells, and to produce normal levels of fluid from deeper wells, made possible an innovative artificial lift option using a Dual Displacement Pump.(Fig. 1) Reciprocated with a standard beam pumping unit using coiled tubing, this production system (patent pending) consist in reciprocating a plunger of a down hole pump, were both motions of the pumping unit are utilized to convey fluid to surface. While in the down stroke production reaches surface through the annular space between CT and production tubing, in the up stroke fluids reach the surface through the annular space between CT and production tubing, The pump design incorporates two independent sets of traveling valves and two sets of standing valves with only one Plunger/barrel configuration.

In 1994 Texaco personnel viewed chemicals as the primary means to reduce water handling costs. They recognized from downhole videos that oil and water remain separated in the tubing-casing annulus. Capitalizing on this revelation of "gravity segregation," they conceptualized a dual-ported, dual plunger rod pump to produce oil and water from the annulus on the upstroke while injecting water on the downstroke. Texaco and Dresser jointly developed this pump and named it the Dual Action Pumping System (DAPS). In January 1995, the first generation prototype was installed. It verified the technical and economic feasibility of this new technology. It substantially increased production while simultaneously reducing power requirements. A second generation prototype was developed to improve the valve design. It has continued to function without problems since its installation in October 1995. Tests in a Rocky Mountain Oilfield Testing Center well and several Talisman wells have further demonstrated that this will be a unique, new tool for the oil industry. These papers will both explain how DAPS works and describe some of the early testing results. Work is continuing to improve the performance predictions. Tests have shown it to be an inexpensive technology that can reduce lifting costs and thereby increase and/or accelerate reserves recovery when the right conditions exist. While many potential applications or benefits of DAPS have been identified, these can generally be classified in three categories: _ Increase oil production _ Reduce water handling costs Reduce potential investment costs

This paper reviews our experience, dating from 1953, with dually completed wells equipped with tandem pumps (two pumps actuated by one rod string). In this span of time newer designs in dual-zone equipment and packer-tubing combinations have antiquated the initial installation. Subsurface schematic drawings depict seven deviations in equipment installed in various wells, which encompass most of the major techniques and assemblies. Commentaries on each method, which include installation and operational problems and production results from specific wells, give an insight into the applications and limitations of each assembly.

This technology utilizes a thixotropic, in-situ polymerized, gelation system. It is designed to prevent gravity slumping to form a chemical packer in horizontal and deviated wells. This system has relatively low viscosities at surface temperature but develops its thixotropic properties in a time frame of 20 to 30 minute as temperature increases while being pumped down hole. This thixotropic blend can be used in wells with bottomhole injection temperatures ranging from 100oF (38oC) to 180oF (82oC). The system utilizes synthetic clays which impart the thixotropic properties to maintain a temporary chemical seal until the second vinyl polymerization occurs to form the final packing seal. The vinyl polymerization system is a low viscosity monomer solution which uses temperature-activated initiators to induce a phase change from liquid to a ringing gel at predictable times.

The dynamic properties of nitrified cements are dependent on the temperature and pressure state of the downhole system as well as the physical properties of the base fluid. The density, viscosity, volume, and rate of a nitrified fluid change as the downhole temperature and pressure circumstances change. Mathematical formulas based on gas density, molecular weight, specific gravity, and Ideal Gas Law provide the means of calculating the fluid properties at anypoint in its pumping history.

Many of us today are being confronted with a new and different problem, that of obtaining maximum production from a given well. This problem can arise from a number of different sources. Perhaps we are starting a waterflood program and we need to utilize our present equipment as far as possible in the life of the flood or perhaps we are finding that out wells are making as increasing volume of water and that we must handle increasing amounts of fluid to obtain maximum production. In addition, there is the everyday problem of those of us who are responsible for equipment selection. We need to know the maximum capabilities of our equipment design and the best methods to utilize these capabilities; we can then select adequate equipment for the full lift of the well at minimum installation cost. This means that at some time in the well life, we must expect this equipment to deliver its maximum production capabilities. Most of users today look at only three or, at the most, four possibilities in our search for maximum production. Many times we do not even attempt to evaluate these various methods to find out which one will give as the best utilization of the equipment at the least cost.

Dynamometer Analysis Plots allow the display of various parameters; both acquired and calculated, during a complete pumping unit stroke. At a user-specified time frequency, the polished rod load, polished acceleration, electrical motor power, and current data are acquired a during a dynamometer survey at a sucker rod lift well. Using the descriptive well information and pumping unit geometry many other parameters are calculated, such as: pump load, polished rod position, polished rod velocity, pump plunger position, pump plunger velocity, existing mechanical and electrical net gearbox torque, instantaneous SPM, and motor RPM. These calculated and acquired dynamometer parameters can be plotted, in pairs, in any combination versus any of four horizontal axis parameters; polished rod position, plunger position, elapsed time, or crank angle. Analysis of operational problems can be aided through the ability to graphically compare the various acquired and calculated data values. Frequently the standard plots of load vs. position or vs. time displayed by analysis software programs are not sufficient to trouble shoot and analyze a sucker rod lift problem. Providing a user the graphic capability to easily select and compare the different acquired and calculated parameters for a selected individual stroke, leads to better understanding and analysis of the sucker rod lift producing conditions.

In this day of high costs and high speed of operation in the petroleum industry, it has become necessary that every person in the industry have an exceptional set of data and information to exercise his best wisdom. It used to be that a man had to have a lot of experience to exercise wisdom. But in this hustle and bustle of high speed economy an employee does not have time to obtain the necessary experience in this fast changing industry. Many of you have learned a procedure of some sort and remember that in a year or two this procedure has been replaced by new theories, much to ones disappointments or confusion. The person who can use other people's experience for basis of his wisdom is the one who will advance more rapidly.

An instrument for pressure analysis to be used in well analysis and study has been needed for some time. A new instrument which can measure differential pressures in the range of 1.25 psi to 28 psi per mm, and a chart speed with an accuracy of .002 of one second is being used in well analysis. This type of study has much to uncover in this field. It could be compared with the first studies of the dynamometer used in rod pumping studies, 30 years ago. The paper will have examples of some of the studies pertaining to tests made on various hydraulic pumping systems.

After the initial studies and decisions have been made and the flood is started, it is then a matter of continuous checking and adjusting of volumes of input water in order to attain optimum results at the producing wells. In order to show how the dynamometer fits into the picture, we will use illustrations of actual cases. However, in the discussion of fundamentals, we shall briefly explain what the dynamometer is and what it does.

A reduction in maintenance and operating costs on pumping well leases can be just as beneficial as an increase in production. Tremendous savings are possible on may leases if a practical dynamometer survey is initiated. The dynamometer and related test data can offer the basic requirements for lease cost analysis. This paper will discuss numerous ways that a dynamometer can be applied to lease studies and will present examples of the resulting improvements.

Oil produced by pumping wells is a major source of income to the petroleum industry. The continual increase in operating and repair costs of pumping equipment has required more efficient and economical operation, in order to maintain a satisfactory margin of profit. Since the pumping well problem is often complicated, accurate analysis requires an exact and complete test procedure, and a thorough study of well data and test results. In order to facilitate testing of the problem pumping well, an organized dynamometer test procedure is presented. This procedure may serve as a reference guide for the seasoned dynamometer operator and may assist in the training of new and inexperienced personnel. The test procedure is designed to guide the well study from the time the tester is notified of the pumping well problem to the final diagnosis.

The DynaPump is a unique rod pumping system that is composed of the pumping unit and the power unit. While similar to a Rotaflex pumping unit, the long stroke feature, it uses hydraulics as the lifting mechanism. The DynaPump offers several benefits such as the use of more efficient motors, smoother rod reversals, internal pump-off controller (better reservoir inflow control), etc. The field performance of a DynaPump system was evaluated on a recent well installation.

During 1997 a customer in Montana called to say that the dynamometer cards produced by the Rod Pump Controller (RPC) were swelling slightly. A swelling or distortion along the vertical axis (load) was noticed compared to the reference card. The horizontal component of the card showing position was changed very little (slight rotation). Was the apparent change in load real, or was the equipment faulty? During each stroke the RPC collects samples from load and position inputs. Pairs of load and position values are sampled every 5 milliseconds. Every 50 milliseconds ten load and position pairs are digitally filtered and plotted to form a surface dynamometer card. For example, at 6 Strokes Per Minute (SPM) 200 points are collected to produce the surface dynamometer card plot. Load is plotted along the vertical axis, position along the horizontal axis to form a surface dynamometer card for each stroke. During RPC setup, a Base Card is collected for reference. A Current Card is drawn every stroke. Current Card load and position values are checked for both absolute value limits and rate of change violations. On-the-fly processing checks for conditions needing immediate response. End of stroke processing compares Current Card area to Base Card area, among other checks. The area enclosed by the surface dynamometer card is a measure of the polished rod workload for a complete stroke. Load measurements from beam mounted transducers, and position inputs from proximity switches supplied data pairs. The Base Card or reference card position input plot had been recorded during RPC setup using a continuous potentiometer. Prox switch position is fitted during RPC setup to permit comparing load and position values on Current Card with Base Card. Position data for Current Card is supplemented by SPM timing data to detect significant changes in stroke length. Beam mounted transducers do not directly measure rod string loads, but give a relative measure of beam deflection. The resulting measurements must be calibrated to provide useful data about rod string loads. Polished rod load cells can directly measure loads, but they are mounted in an area that is subject to damage (especially during workover). Polished rod load cells are also generally more expensive than beam mounted transducers. The acceleration and deceleration of long rod strings during a typical pumping unit stroke introduces more factors. Rod string dynamics introduce variables such as: momentum, vibration, rod stretch, buoyancy, valve pulsations, and noises both electrical and mechanical in nature. Load cells and beam mounted transducers challenge designers to produce consistent results needed for production analysis. Load spikes and other challenges need to be dealt with. Obtaining a reliable indication of rod loads during fluid production involves trade-offs. Beam-mounted transducers are mounted away from workover action. Welding or clamping is used to mount transducer on beam. Improper mounting can lead to inconsistent results. They are not as likely to be damaged as polished rod load cells. The joint investigation of customer concerns started by closely looking at the results to determine what was happening. The operation of the rod pump controller seemed to check out OK. The card swelling seemed to correlate with a real dynamic load increase. Further investigation by the customer showed that the well would need an emulsification treatment soon after the dynamometer cards expanded. The field results showed that results were somewhat consistent, and might be useful for scheduling emulsion treatments. Armed with this new information, the conditions were investigated to see what could be done to harness the observed changes and make a useful tool.

This paper presents field procedure, calculation techniques, and results of two gas well reserve tests utilizing bottom hole pressure drawdown and buildup data obtained with short duration production testing immediately after initial completion. Results of tests are compared with reserves indicated by subsequent pressure-cumulative performance. Both wells were gas discoveries in one-well reservoirs with extremely limited reserves.

Historically, maximizing completion and stimulation effectiveness in wells with multiple productive zones was hampered by lack of robust data. It is now possible to assess early-time zone-by-zone stimulation effectiveness (apparent fracture half-length) and reservoir quality (effective permeability-thickness) without the need, cost or risk of in-well operations, such as a spinner survey. This is accomplished by employing a series of molecular markers in each stimulation stage, which can be quantitatively analyzed over a sustained period of time. When used with the subsequent commingled total well production and the fracture closure flow periods, a pressure transient drawdown analysis provides the necessary descriptive knowledge. In many cases, additional information can also be gleaned regarding zone-by-zone free water contribution. Example stimulation results will show the effectiveness of this procedure. The paper will demonstrate the effectiveness of this technique and the value operators garner from it.

For decades producers have fought the problem of lost pump efficiency due to downhole gas interference. Downhole pumps can lose 20% to 100% of published efficiencies due to free gas problems. This is especially true when the pump is placed above the perforations. To correct this problem producers have tried a variety of remedies. Some of the remedies, such as knockers, spring-loaded balls and backpressure valves. do not directly attack the problem. Although these tools have proven to be helpful in pump operations they do not solve the root problem. Gas interference in reciprocating pumps causes lost production. premature pump failure. rod parts and excessive wear on surface equipment. Other types of lift equipment are also affected by gas interference. Progressive cavity pumps require liquid to lubricate and cool the polymer sealing materials. Free gas will greatly decrease the efficiency and life of these pumps. This is also true with submersibles as they require a constant flow of fluids for motor coolant. The most common downhole separator is made from materials found in pump yards. A joint of pipe is perforated and orange pealed on the bottom. This is attached to the seating nipple or lower barrel coupling and a dip tube is attached to the pump. Gas separation takes place between the dip tube and inside diameter of the perforated sub. This tool is often called a "Poor-Boy" gas separator (Fig 1 ), The Fluid efficiency of this separator is limited to about 50 BPD due to the limited space between the dip tube and outer case. Pressure differentials created by the upstroke of the pump add to the tools inefficiency. On the upstroke a pressure differential is created between the inside of the separator and tube casing annulus and fluids flow into the gas separator. Fluids surrounding the separator often contain 75% free gas. Considerable mamounts of gas are drawn into the separator and very little separation takes place due to the pressure differential. In a conventional "Poor-Boy", most of the fluid and gas flow occurs on the tip stroke and most of the gas discharge occurs on the domnstroke creating low efficiency.

Power consumption of an electric submersible pump installation may be categorized into three components, the energy required to perform useful work which is equivalent to the net hydraulic load divided by the product of pump and motor efficiencies, the energy absorbed by tubing friction which is equal to the dissipated hydraulic energy divided by the efficiency product, and power cable electrical losses. An improved design technique is presented which brings the two preceding categories of energy loss into economic perspective. The interrelated effects of tubing friction, voltage drop and motor voltage on ESP power consumption are demonstrated, as is the degree of desirability for using a motor of the highest available voltage. An equation is developed for calculating power consumption for combinations of tubing size, power cable size and motor voltage, which is useful in making economic evaluations of alternatives. Variations of power consumption are illustrated graphically for various combinations of tubing size, power cable size and motor voltage. Also illustrated is the effect of the nature of a specific net hydraulic load, i.e. the product of rate, lift and specific gravity. Practical examples utilizing the design techniques herein developed are presented and comparisons are made to designs based on common practice.