A significant available resource of unrecovered mobile oil resides within Grayburg reservoirs as a result of low ultimate recoveries of less than 30 percent of the large estimated volume of original oil in place. This low ultimate recovery from conventional primary and secondary recovery methods is due mainly to the heterogeneity typical of these reservoirs. Evidence of this heterogeneity is well displayed in the Dune field by significant production inequalities, particularly within the Mobil University Unit 15/16. The cumulative production from Section 15 is about 10 million barrels, whereas that from Section 16 is only 2 million barrels. This difference between the two adjacent sections cannot be attributed solely to varying production practices, but rather to major changes in rock fabric and depositional facies. Within Section 15, wells from the same reservoir have yielded widely varying amounts of total production, further demonstrating even smaller scale heterogeneity.

Inflatable impression packers are not new; they have been around for a number of years.1"2"3 However, their use has been very limited, probably due to one or more of the following limitations: 1. High differential pressure was required to squeeze impressionable material into cracks or perforations, which necessitated an inflatable packer which was expensive to manufacture and difficult to make longer than about 10 feet. 2. The inflation pressure often had to be held for up to 10 hours in order to be able to retain an impression. 3. The inflatable packer had to be returned to its manufacturing plant to be repaired or redressed. A new field-redressable, 30-ft long, low differential pressure inflatable impression packer system has been developed. Also, new impression materials which are oil resistant and which can make and retain in situ impressions in 10 minutes or less have been developed.4 During the development and field testing of this inflatable impression packer system, the minute detail and consistency of the impression retrieved on the new impression material suggested that, with careful calibration, accurate correlations could be made between impression size and actual in situ hole size. Further investigation indicates that the amount of impression material extruded into a perforation. This paper originally appeared as SPE 5707 and is reprinted here through the courtesy of the Society of Petroleum Engineers. under a head of noncompressible fluid is proportional to the formation permeability connected to the perforation. This paper describes the eight critical parameters which must be known and/ or controlled to calibrate impression size to actual size and extrusion height to effective connection to formation permeability in situ.

The unprecedented rile in the cost of tublar goods has made operators look for cost-effective ways to extend tubing life. Fasken has found that using poly lined tubing in rod pumped, injection and disposal wells has been a good option in reducing well failures as well as extending tubing life. Installing a poly liner over damaged IPC tubing is one example of using this liner system and has also been successful in several other applications.

For the past few years there has been a lot of effort expended on examining potential electrical cost savings in the oil field. This paper presents efforts to examine the electrical savings in rod pumping operations by: 1. Motor changes and downsizing 2. Reversing the direction of rotation 3. Changing well operation run times and frequency 4. The effect of installing a down hole gas separator All of these operational changes are inexpensive and the electrical cost savings compared to cost of making the changes are discussed.

From its first development in the early 1960's an effort has been made to optimize a stimulation procedure for the Canyon Sand formation in Southwest Texas. Many attempts have been made to find a fluid system that would maximize stimulation results while minimizing treatment cost and formation damage. As a result, a variety of fluid systems have been pumped consisting of a wide range of both fluid and proppant volumes. This paper investigates historic stimulation practices over eight selected study areas. These procedures are then evaluated based on long-term production data in an attempt to identify an optimum treatment size, for each area, in terms of both fluid and proppant volume.

There are various oil and gas fields across the United States that have been producing for over 100 plus years. While each area experiences different types of issues regarding rod failures, tubing parts, paraffin, scale and corrosion issues, many operators struggle with or how to properly treat these issues.
By banding Capillary string to the outside of your production tubing, you can now properly treat with pinpoint inijection to the exact area that needs to be treated.
Starting in April 2013, you will be able to treat your issues with a Capillary string below a tubing anchor with Weatherford's new Capillary Injection Tubing Anchor. By running this system you will be able to pinpoint treat with your chemicals at the bottom of your pump to treat your rods and the inside of your tubing.

Carbon dioxide corrosion studies of oil-well portland cements were initiated using a new microsample technique to determine the effect of carbonic acid on portland cement slurry formulations and to develop a high carbonic acid corrosion-resistant cement for carbon dioxide Enhanced Oil Recovery applications. Earlier results from studies using two-inch API cement cubes showed carbonic acid had essentially no effect on cement after relative short test periods at elevated temperatures. Similar results with two-inch API cement cubes also were reported in recent literature. Because carbonic acid corrosion in cements was difficult to observe and measure using two-inch API cement cubes, a new microsample technique was developed. Use of this new technique, which represents an accelerated testing method, showed oil-well cements undergo a rapid deterioration in a wet carbon dioxide environment. Similar tests with two-inch cubes showed essentially no cement deterioration under the same conditions. Experimental details of this new microsample technique are discussed. Data relating cement strength loss and carbon dioxide penetration depths to cement type and slurry formulation are reviewed. Included in the discussion is a new cementing formulation which shows significant promise as a high carbon-dioxide-resistant, oil-well cement.

Carbonate formations are predominate in the Permian Basin and as such are commonly stimulated with acids. Success of an acid treatment is dependent on knowledge of the reservoir, design techniques and execution; and emphasis on obtaining good zone coverage. Case histories of acid stimulation, with production results, are presented covering San Andres and Devonian horizontal wells and deep hot Ellenburger wells. Treatments varied from high rate matrix to hydraulic fracturing operations. Discussed are key issues to overcome in order to obtain an effective stimulation and methods employed, with particular emphasis on zone coverage.

Carbonated waterflooding is an enhanced oil recovery process developed in the early 1950's that may have potential application in several West Texas reservoirs. The process consists of saturating injection water with CO, in order to swell the remaining oil-in-place, and thereby increase the amount of recoverable oil in a reservoir. The process usually involves less investment and CO, demand than miscible CO, flooding. The effects of carbonated waterflooding on equipment material performance were monitored during a two well carbonated water injection pilot test conducted by Amoco Production Company in the Slaughter Field, Hockley County, Texas. Stainless steel and aluminum bronze material showed no deterioration during the test period. However, severe problems were encountered at holidays in the internal plastic coating of carbon steel pipe and fittings. Injection well material performance data and observations are presented to support these findings. In addition, the surface equipment design used to saturate injection water with CO, will be presented. No attempt will be made to discuss the impact of carbonated waterflooding on injection well or reservoir performance.

Shortages of drill pipe have hit the industry hard for the past few years. Not only has there been a lack of availability of pipe, but costs to replace discarded strings and strings for new rigs have risen sharply. Therefore, the subject of proper care and handling of drill stems becomes increasingly more important. Owners and users must get maximum life with a minimum of problems for their drill strings. Much has been done to increase the life of drill strings, but much more can be accomplished with a broader understanding and practical approach to proper care of drill stems. Although the subject of care and handling of drill stems is not new to the industry, it must be recognized that new people enter the industry every day. How well they are trained and acquainted with possible drill stem problems and the proper care of drill stems will have a direct effect upon the life of a drill string. Therefore, one of the most important steps in proper care and handling of drill stems should be to assure that all personnel associated with using and handling of drill stems are knowledgeable as to why drill strings deteriorate. Most drill pipe degradation, including tool joints, can be categorized into four broad groups: fatigue, corrosion, mechanical damage, and wear.

Manufacturers attempt to deliver sucker rods to the user in the same condition as when they left mill. The processes of unloading, storage, and transportation to the field must be just as carefully carried out, since carelessness at any of these stages can nullify the efforts made at any other stage.

The sucker rod manufacturers are fully cognizant of the fact that sucker rods are required to fulfill one of the most stringent tasks that is offered by today's petroleum producing program. In an effort to combat this challenge the industry has solicited the full support of this nation's great metallurgical research capacity. However, basic steel and steel alloys are merely the initial step toward an end, and the responsibility of providing the necessary medium is entirely the responsibility of the manufacturer, and the degree of responsibility lies with each individual manufacturer. The capability, integrity and reputation of the manufacturer is entirely reflected in his eventual product.

Your injection pump is the heart of your water flood or saltwater-disposal injection system. We, realizing the necessity of continuous injection in a flood, will attempt to pass on information based on past experience and observation that will aid, through proper maintenance, to keep your pump in operation.

The long stroke hydraulic pumping unit, as we know it today, oftentimes may seem strange to the new operator, even though it has been operating successfully in parts of the oil field for the past fifteen years. Justifiably so, the hydraulic long stroke unit may at first seem unfamiliar to the new operator, since for years previous to the introduction of the long stroke hydraulic pumping unit the oil fields had know no other means of sucker rod pumping than the old familiar sight of a beam moving up and down. However, just as the rotary drilling rig has followed the cable tool rig, so has the hydraulic long stroke unit followed the beam pumping unit.

The rod and tubing pumps of today are far advanced over the oil well pumps of twenty and thirty years ago. Wells were shallow and that time consisted of common working barrels and the old bowspring cups. As well were drilled deeper; longer runs were required to lower lifting costs, metals were experimented with to assemble the forerunner of the present day precision rod and tubing pumps. The original metal pumps were built with plungers turned down in lathes to fit each individual barrel so that interchangeability was impossible. In recent years the American Petroleum Institute committees, in collaboration with manufacturers and oil producers, have established basic dimensions on all pumps which will allow any pump shop to stock API parts to repair all types of pumps.

This paper will deal with the four cycle spark ignition, carburetor engine designed to operate on the gaseous or liquid fuel or a combination of both as practically all so called high speed pumping engine are of this type. Actually, the correct classification of these engines should be "medium speed" as compared to engines being used in other industries operating as much higher speed.

The subject for today is the Care and Operation of Hydraulic Pumps.

All internal combustion engines are built to give long, trouble free service. An internal combustion engine, in order to operate, must have fuel, air, oil, and a coolant (usually water). The condition of these four items determines the useful life of an engine. Let's discuss each of these and attempt to point out desirable standards and how to combat below standard factors. Since the majority of engines used are gas engines, we will talk about natural gas as a fuel. Most gas used is a field gas and engine users don"t have much choice but to use it as it exists. In discussing fuel, we must also consider its effect on lubricating oil.

An internal combustion engine must have air, water, fuel, and oil fed to it in order to keep it operating. The condition of these four items determines the useful life of the engine. We will attempt to point out what the standards are and the best methods of combating the "below standard" factors where we have no choice but to use them as they exist in the field. It is not possible to describe and elaborate on fuel alone without considering its affect on the lubricating oil.

You men as users and myself representing a pipe manufacturer are both vitally interested in getting satisfactory service from our tubular goods. Engineering wise, there are three major factors which control this: 1) proper manufacture 2) Proper design, 3) Proper use.

Unitized Emulsion Treaters have been a reality for over 20 years. They have been employed in the Permian Basin for over 18 years. This type of surface equipment has become almost a necessity and is therefore considered standard equipment on most leases. The present day vessel is an efficient, pressure operated, automatic treating plant. Contrast this with the early day methods of treating oil in a pit with steam coils, or spreading the oil out in a thin layer and letting the sun warm and treat the oil. The present day practice of using Unitized Emulsion Treaters is an example of the oil industry's desire to conserve our natural resources.

When, where and how do you plan your career? No. 1, you decide what you really want! What do you want to accomplish during your life? Not what your parents wanted. Not what your spouse or children want. But, what do you want? Deciding what we want is difficult, getting it is even harder. To do this we need a life plan. We need to think of personal growth and values. We need to maintain health and fulfill spiritual needs. We need to develop our personal lives and to establish fruitful relationships. The problem is that we live in a world of change and risk. Change in our world is occuring faster than ever before in history. To move forward we must gamble. Somehow we must be flexible and adapt to this changing world but still steer a constant course toward our goal. We need to stack the odds in our favor, and we can. In the ultimate, you are the person who controls your life. You are the one who determines your forward progress.

Wolfcamp producers in Howard County, Texas have to be fracture stimulated to be economical. However, the low frac gradient and bottomhole reservoir pressures make formation closure slow and proppant retention in the created fracture during initial production difficult. This has led to many of the wells requiring wellbore cleanouts and in some cases multiple cleanouts. Various methods are available to overcome this problem. Methods of proppant flowback control vary from materials added to a proppant pack to provide physical stability, forced closure techniques, tail-in with curable resin coated proppants, etc. The most extensively used method in most areas of West Texas is the tail-in with curable resin coated proppant. Resin coated proppants consist of a substrate of sand or ceramic particle coated with multi-layers of phenolic and other specialty resins. These resins provide grain to grain bonding and additional particle strength. Presented are case histories of Wolfcamp producers fracture treated using 20/40 Mesh, White Sand and using a tail-in of curable resin coated sand comprising 15% of total proppant pumped. The case histories show that use of a resin coated proppant added an additional $25000 to $30000 to treatment costs, however, a single wellbore cleanout of sand costs $24000 to $27000. Making the cost of running a resin coated proppant tail-in

In all acidizing programs, a critical factor for success of the treatments is distribution of the acid between all productive zones. Since most producing wells are not homogeneous and contain layers of varying permeability, even distribution of the acid is a difficult task. This paper will present the results of approximately 55 high permeability wells from the Cantarell field in Mexico ranging from 1,000 to 6,000 md, which have been acidized using a novel acid diverter based on associative polymer technology (APT). This polymer inherently reduces the formation permeability to water with little or no effect on the permeability to hydrocarbon. Data from production logs from several of the treated wells will be presented which show excellent oil production distribution along the perforated intervals. In addition, production logs will also be shown for wells acidized with other diverters, such as foams and in-situ crosslinked acid, which showed poorer results.

As operators strive to increase production from existing reservoirs with depleted reservoir pressure, the use of under-balanced drilling and underbalanced horizontal drilling is becoming more widely used. One of the primary problems to overcome in drilling under-balanced is designing a circulating "fluid" that has an equivalent circulating density below the reservoir pressure. This paper discusses the mathematical equations used to design air drilled "under-balanced" wells. It will also show how these equations were used to design four separate wells. The presentation of actual field data will validate these equations and computer modeling used. (See Table 1) The four wells will include 1) 17,000 TVD well drilled into the Ellenberger formation with reservoir pressure at 1200 psig, 2) horizontal well drilled into the Petit formation at 5900 ft. TVD with reservoir pressure at 210 psig, 3) horizontal wells drilled into the upper Penn Formation at TVD 7800 ft. and reservoir pressure of 1000 psig., and 4) deviated wells drilled into the Ellenberger formation below 13,000 feet TVD and reservoir pressure of 600 psig. The mathematical equations used were developed by Dr. William C. Lyons of New Mexico Institute of Mining and Technology in Socorro, NM. Computer simulations for these wells were run by David Giffin on software developed by Boyum Guo and Dr. Lyons. Each of these wells was drilled using air drilling techniques. By measuring the pressure at both surface and bottom hole conditions, the validity of the mathematical models used has been established. Air or other compressed gas can be used to reduce equivalent circulating densities to accommodate almost any reservoir pressure.