As the production of oil increased, the emulsion problem increased. The companies, realizing that some better way of separating the water and oil had to be devised, installed large tanks, both wooden and steel, placing steam coils inside them. This method proved superior to the old pit system, however, it was far from perfect. Not only did the emulsion that was not treated create a disposal problem, but much of it was impossible to break down with the heat alone, consequently other methods were sought. Thus the first commercial treating chemical was used.

Paraffin is costing the crude oil producers untold millions of dollars per year. In down time, loss of production, plugged wells, lines and emulsified oil in storage tanks. This problem has been attacked in many ways and until a few years ago, the removal of such deposits was done by mechanical methods, oil producers sought the use of chemicals such as solvent and paraffin inhibitors, of which there are several chemical formulas on the market that are doing the job economically and well, if they are properly applied.

Thirty-two gas wells were incorporated into a computer program in the Greta Field, Refugio County, Texas. This computer program includes gas measurement for all 32 wells and control of 15 wells. Individual computers for each well are located at the lease metering sites. Flow volumes are recorded, and wells are controlled from a console located at the Tom O"Connor Gas Plant. Transmission of signals between computer and console is through an aerial multiconductor cable. The use of computers has eliminated the need for 24 hour pumping service to regulate volumes and the need for the orifice recording charts.

This paper contains a discussion of the design and operation of the electric immersion heating element as well as the results and interpretation of the field test that was conducted.

This paper describes the use and results of using expanding cement to repair casing leaks in West Central Texas. In the past, casing leaks were squeezed using Class C cement (high sulfate resistant. This would take from three to five hours and often several stages, The use of expanding cement has cut the time required for squeezing to one-half to two hours, usually requiring only one stage. This method uses the high gel-strength cement to hold its own hydrostatic pressure to give a quick shut-off to casing leaks. The weight of this cement is heavier than ordinary Class C cement.

The ever-increasing shortage and resulting higher prices of natural gas and oil make it important to conserve fuel whenever possible. One way is to remove all free water from the produced oil Stream before treating the emulsion. This paper discusses the application, design installation, operation, maintenance, trouble shooting, and corrosion protection of free-water knockouts used for this purpose.

Factors to he considered in the selection of inhibitors and treating techniques used to control downhole corrosion in gas wells are discussed with special attention to deep, hot wells. Corrosion monitoring is recognized as a complex but necessary part of any corrosion control program.

Corrosion of oil field production equipment is a serious problem which is many times not given the consideration it deserves. Every year, the oil industry pays a corrosion bill running into millions of dollars. In many cases, the fact that some of their sots can be eliminated is not realized, and others, the ravages of corrosion are not recognized. It is now possible in some cases to economically allay the reoccurring costs of maintenance of equipment, and in others to percent the actual destruction of the equipment. Several methods of providing corrosion protection have proved satisfactory for use in oil field equipment. Each one has its special uses. No one plan or method is the most economical for all conditions. One of the most important and most widely used is protective coatings. Use of these materials goes back to the early 1940"s. Where the proper coating is properly applied, protective coatings have given excellent results.

A new analytical procedure is described here for predicting well performance and analyzing completion effectiveness of wells which have a significant pressure drop from turbulence. (In this discussion we use the term turbulence to describe both turbulence and all other rate dependent deviations from darcy flow such as inertial effects.) The procedure is more applicable to gas well completions but has been applied to a high-rate oil well. In particular, the new procedure should provide a powerful analytical tool in areas where most wells have high production potential. The procedure can be used in wells requiring sand control measures and in hydraulically fractured wells to determine if the cross-sectional area open to flow into the wellbore is sufficient. It also provides an indication of perforation effectiveness in normally completed wells because an abnormally high turbulence coefficient indicates too few open perforations. Incidental to determination of a turbulence coefficient, the new procedure provides a laminar flow coefficient which includes skin effect. If permeability thickness is known, an estimate of skin effect can be made from the laminar flow coefficient. Also included in the theory is an explanation of the effects of partial completion or a change in completion geometry on pressure buildup results when the turbulence pressure drop is significant. The analysis procedure permits determination of turbulence effects on completion efficiency irrespective of skin effect and laminar (darcy) flow. The required data are either: (1) two or more stabilized flow tests; or (2) two or more isochronal flow tests. Flow rates and bottomhole flowing pressures must be known in either case. Transient pressure data are not needed and bottomhole flowing pressures calculated from surface pressures may often be sufficient. The previous means of determining the turbulence coefficient have required some means of obtaining kh; usually a buildup test coupled with several production tests or a series of buildup tests. These were used to determine a total skin effect, s", which included the turbulence term. The s" values were then plotted versus flow rates. Actual skin effect and turbulence coefficients were then calculated from the intercept and slope. The new method avoids the necessity for transient data from a buildup or drawdown test and permits a direct plot of pressure data versus rate. The added simplicity should make the new procedure much more useful in direct field applications.

Proper use of d-exponent data accurately predicts formation pressures while drilling in the Delaware Basin. This paper shows how this information can be used to minimize drilling costs by: 1) Proper maintenance of well control. 2) Selection of casing seats. 3) Prediction of hole stability caused by heaving shales in an underbalanced system.

Test data collected from the TTU test well plus field data will be used to show the impact of pump clearance and pumping speed on pump slippage. Pump slippage significantly increases with increased well depth due to high temperature reducing water viscosity and increased differential pressure acting across the plunger. Specifying plunger length and other recommended practices will be discussed. A procedure to design the pump clearances based on sensitivity of the various correlating parameters will be presented. The Patterson Pump Slippage equation is discussed and a totally theoretically equation is shown to give similar slippage results which only adds to the credibility of the method. Pump efficiency can dramatically decreases at slow pumping speed when pump clearances are large. Additional energy must be input to the sucker rod pumping system to re-pump the portion of the pump's displacement lost to slippage. Even with the equations and guidelines available, the operator frequently uses too large of pump clearances for the well conditions and the reason for the low resulting production rate can be difficult to identify. Use of open or tight pump clearances should be based on well conditions. For large clearance pumps the efficiency decreases as the pumping speed is decreases plus the efficiency decreases when pumping from deeper depths.

This paper serves to up-date applications and results of the Vannsystem. The Vannsystem is the process of running large casing guns on tubing for maximum completion performance. Prior papers on this system have dealt primarily with maximum differential perforating to overcome formation damage. The 3,000 plus wells completed using this technique included such applications as tight gas sands, highly unconsolidated sands, intervals of several hundred feet, formation evaluation, off-shore, injection wells, and others. Recent key applications, along with case histories, will be reviewed. The use of tubulars makes it possible to customize completions under such a variety of conditions.

Heightened regulations and enforcement on air emissions from oil and
condensate tank batteries have many companies evaluating new technologies for capturing these vented natural gas emissions. These gas streams are a challenge to capture effectively, especially on truck loaded batteries. This talk will focus on "best in class" technologies to capture these gas streams effectively and consistently

During recent years, multiple completions have become more commonplace. This is to be expected due to the obvious economic advantages derived from producing two or more allowable while having to drill but one hole. Problems encountered in producing multiple completions, as in single completions, are usually minimal, until artificial lift is required. With the installation of lift equipment, production from zones beneath a packer can be adversely affected if the pump intake pressure is below the bubble point of the produced fluid and the gas production is not adequately vented. The use of vent strings in these cases can result in maintaining producing rates at or near normal, and thereby increase income and shorten producing life over what would be anticipated if the well were produced unvented. This paper presents some limited data on producing from beneath a packer with the gas production vented and unvented. Venting through one-inch tubing strings is compared with annular venting. A method, with a trial and error solution, of predicting unvented production is also presented.

Significant advances have recently been made in laboratory attempts to measure realistic fracture conductivity values for proppants at reservoir conditions. This paper will give a brief overview of recent work throughout the industry related to conductivity testing, and efforts being made to simulate the environment of fracturing proppants during a well's producing life. Also presented will be data showing that test results can be significantly different when using wet gas as the flowing medium following a short period of flowing brine water. Listed below are the nine most important test parameters that need to be incorporated into the test procedure: -Reservoir Temperature -Extended test times -Core wafers -Gel residue within the proppant pack -Gel filter cakes from dynamic fluid loss tests -Shear preconditioning of fluids in fluid loss tests -Frac fluid clean-up -Wet nitrogen gas as flowing medium (to model gas wells) -Multiple closure stress values. Previous authors have modeled some of these variables, but this paper will present data where all parameters listed above are included. These test results will allow an operator to more accurately model a fracturing treatment with a design simulator and thus predict the post-frac production using a reservoir simulator.

Electrical submersible pumping is perhaps the most inflexible of any artificial lift method because any given ESP pump can only be used in a specific, quite restricted range of pumping rates. If used outside its recommended liquid rate range, the hydraulic efficiency of the pump rapidly deteriorates; efficiencies can go down to almost zero for pumping rates lying well outside of the lower or upper limits. In addition to the loss of energy and the consequent decrease in profitability the ESP system, when operated under such conditions, soon develops mechanical problems that can lead to a complete system failure. An improper installation design or inaccurate information on the well's inflow capability always results in a mismatch between the design rate and the actual pumping rate. The usual result of these troubles is a workover job and the running of a newly-designed ESP system of the proper lifting capacity. Since the capacity of the ESP system, without using an expensive VSD (variable speed drive) unit, cannot be easily changed, wellhead chokes are often used to restrict the pumping rate and to force the ESP pump to operate within the recommended liquid rate range. This solution, of course, is very detrimental to the economy of the production system because the pressure drop across the choke causes high hydraulic losses and a considerable waste of energy. The paper investigates the negative effects of surface production chokes on the energy efficiency of ESP systems using NODAL analysis tools. The proper way of conducting a NODAL analysis for this purpose is detailed along with the description of power flow in the ESP system. The calculation of energy losses in system components is detailed and the relative importance of the individual losses is shown. The elimination of the problems associated with the use of surface chokes is investigated and the proper parameters of the necessary VSD unit are found.

The scope of this paper includes a brief introduction about On-Off tool, design and construction, their applications, operational procedures, and general load carrying capabilities. The paper discusses some advantages gained by installing an On-Off tool such as, the ability to repair or replace the rod string without unseating the pump, the ability to break the sucker rod string just above the pump eliminating stripping job and the ability to run oversized tubing pumps.

The concept of using chemical additives to reduce drag or friction of fluids flowing in turbulence has been a well-known phenomenon for many years. It has been the subject of several papers both in and outside the petroleum industry. There are many stimulation treatments now being performed which would be virtually impossible were it not for friction-reducing chemicals present in the stimulation fluids. Even small-volume acid washes done through small-diameter tubing or coiled tubing units utilize friction-reducing chemicals. Friction reducers, used in small quantities, can provide reduced surface treating pressures, higher injection rates, and lower hydraulic horsepower requirements. Historically, powdered-type friction reducers have been used in the petroleum industry for most aqueous fracturing treatments. The common polymers used to reduce friction on a large scale are guar gum, derivatives of cellulose, and synthetic polymers such as polyethylene oxides and polyacrylamides. Synthetic polymers generally provide higher friction reduction at lower concentrations than do the natural polymers and cellulose materials. Advances in polymerization techniques have made possible the development of polymers in liquid form. Now, synthetic friction-reducing polymers, similar to those previously used as solids, can be obtained in liquid form making handling and mixing less difficult. Liquids do not have a tendency to lump when added to aqueous fluids as do dry powders. When lumps form, they are not easily dispersed and can reduce the material available for lowering friction pressure. Also, the addition of liquid systems to treating fluids can be uniformly controlled. Using proper guidelines, it is possible to select a polymer system which provides good friction reduction, is stable in concentrated acid solutions for extended periods of time, and is compatible with most acid additives. This paper compares the properties of a liquid acid friction-reducing agent with several commonly used powdered materials. Some guidelines for selecting an acid friction reducer and laboratory testing of friction reducers are discussed. Successful field results using a liquid friction reducer in acid are also described.

This paper discusses the use of AutoCAD, a popular PC CAD (Computer Aided Design/Drafting) application package, for calculation and analysis of water flood injection profile data. By heavily utilizing the customizing capability of the AutoCAD program, calculational accuracy and repeatability are enhanced. Additionally, the well log analyst is able to more readily verify and validate assumptions during the interactive data analysis phase. The theory and application of profile analysis will be discussed: included are example calculations. Additionally, AutoCAD customizing techniques and programming examples will be discussed. Finally, the automated use of AutoCAD to facilitate multiple well presentations (historical and intra field) will be presented.

This paper discusses the use of AutoCAD, a popular PC CAD (Computer Aided Design/Drafting) application package, for calculation and analysis of water flood injection profile data. By heavily utilizing the customizing capability of the AutoCAD .program, calculational accuracy and repeatability are enhanced. Additionally, the well log analyst is able to more readily verify and validate assumptions during the interactive data analysis phase. The theory and application of profile analysis will be discussed: included are example calculations. Additionally, AutoCAD customizing techniques and programming examples will be discussed. Finally, the automated use of AutoCAD to facilitate multiple well presentations (historical and intra field) will be presented.

This paper presents the practice of using downstream chokes in unloading injection pressure operated (IPO) gas-lift valves. The practice helps to assure effective unloading and may provide protection against erosion damage during the unloading process. It has several other benefits that are discussed in the paper. A gas-lift valve/choke model has been developed. It provides accurate predictions of the gas passage through the choked valve during the unloading process. And, it can help to analyze existing gas-lift performance, where the objective is to determine which valve(s) are open and how much gas is being injected through them. This model is described in the paper.

Coatings of various materials are used to improve corrosion, abrasion and scaling resistance of ESP components. This paper will briefly discuss some of the coatings with a focus on Teflon and it's potential to increase run time. A specific application will be discussed in detail. A completely coated pump was run between uncoated pumps in a New Mexico well that produces significant solids. The well was pulled after a 224-day run and all pumps torn down and examined. This paper will review the findings of the tear down and implications for future Teflon coating applications and tests.

Due to encountered influxes of water while attempting to gain consolidation around wellbores and/or their tubulars, cement can have difficulty in achieving the needed sealing and preventative state necessary for zonal isolation. High influxes of water present across these areas needing remediation can deteriorate the cement at any state from its being placed through the time it takes it to form and develop enough strength to resist this environment. Presented are trials, developed techniques and results based on incorporating crystallized co-polymer super absorbent materials mixed with cement and also as a pre-flush system in conjunction with cementing operations to address a variety of influx problems around wellbores. Data includes laboratory analysis and performance evaluations generated while testing and performing these cement operational solutions. Diagnostics used to arrive at a best fit solution are also detailed and discussed.

As fluids are produced from a reservoir, zones of higher permeability and correspondingly higher flow rates create channels for the preferential movement of fluids.

By coupling the communications power of the internet with the latest in reservoir simulation technology, it is now feasible to direct oil and gas field development in near real-time, using a continuously updated computer model that matches and reflects the actual rates and pressure data observed in the field. While quarterly or monthly updates are probably sufficient in most cases, operators have the option of updating the model weekly or even daily in order to meet the needs of each situation. This ground breaking approach can remove much of the risk from evaluating well completions, optimizing the location of offset and infill wells, predicting reservoir pressures, flow rates, reservoir drainage patterns, identifying the most effective completion methods, well spacing patterns and many other field management decisions. This paper illustrates how this kind of dynamic reservoir simulation can be implemented, even for small, remote production locations, and it cites examples of where this has already been tried, the results that were obtained and describes the experience of those who have actually implemented this approach. The capability now exists for operators, regardless of size or location, to model every new development well (prior to drilling), identify the most cost-efficient reservoir drainage plan and adjust that plan in an ongoing manner based on actual field/well behavior.