The Cement Bond Log/Variable Denisty Log (CRL/VDL) service is used to determine the quality of cement bond to casing and the formation. Some of the recommended uses for the CBL/VDL are (1) Determine if vertical isolation exist between zones. (2) Check effectiveness of a squeeze cement job. (3) Check possible damage to cement by high pressure testing or injecting. (4) Locate cement top. (5) To study various cementing techniques. Figure 1 displays a standard Log presentation of the CBL/VDL. The CRL/VDL Log displays a CBL amplitude curve, VDL display and a transit time curve. In addition, the Gamma Ray, Casing Collar locator and Bond Index curves will appear. The CBL curve, which is located in track two is a continuous measurement of sound pulse amplitudes after they have traveled a specified length of casing. These amplitudes are at a minimum in well bonded casing and at a maximum in poorly bonded (free) casing. The VDL display in track three, complements the CBL amplitude curve by providing additional information about the quality of cement to formation bonding. The VnL displays the varying amplitudes of the arriving sound signals as variations of light intensities. The sonic transit time is recorded in track one and is used in conjunction with the CBL/VDL to verify their accuracy. The interpretation methods used with the CBL/VDL compare the response of all three displays to determine the quality of cement bond, since varying parameters may cause one curve to imply false information if analyzed alone.

A new, multi-purpose acquisition and control system makes monitoring and controlling various laboratory devices easy. The system, built specifically for use in an oil field laboratory, can monitor and control eight laboratory instruments simultaneously. This paper discusses the capability of the system

This paper discusses the use of cement linings for internal corrosion protection of steel pipe in oil field water handling systems, including various cement lining materials, means of application and economics.

In the search for new technology in materials to protect steel line pipe and tubing from internal corrosion, production and facility engineers sometimes overlook cement lining, the oldest and frequently the best system available for internal corrosion control. The purpose of this paper is to re-introduce cement lining to a new generation of engineers.

A test was developed to evaluate cement spacers under conditions simulating mixing in the field. The results have shown that some products did not support barite acceptably well. Dynamic circulation tests demonstrated that spacers did not have the ability to remove mud filter cake as they are widely claimed to do. A test was developed to determine the effect of cement filtration control additives on the filtration from cement slurries through wellformed mud cake. It was found that the additives had little or no effect. Therefore their use in the field for primary cementing has been curtailed in some areas and is under review in others.

Cemented fiberglass liners have been run and cemented in 51 injection wells in the Shell-operated Denver Unit, Wasson Field, in the past two years. Fiberglass was chosen as the most economical corrosion-resistant alternative to steel for use in the oxygen-saturated injection water. The liners were run and cemented by conventional liner setting techniques. They were then perforated and the formation acidized using a cup-type straddle packer arrangement. Other than using running and completion techniques designed to avoid setting slip-type tools in the liner, no special precautions were used. Drilling out cement in the fiberglass with conventional rock bits apparently caused no damage to the fiberglass. No major problems attributable to the fiberglass have been encountered to date.

Several unique conditions existed which influenced Gulf Oil Corporation's selection of multi-stage Centrifugal pumps over multi-plunger pumps at its Goldsmith (5600 ft.) Water Injection Plant in E&r County. Texas. However, the factors taken into consideration in this particular case are applicable to the design of any high volume, high pressure water injection plant. Before selecting the type of pumps to be used, certain assumptions must be made. The volume of fluid and the pressure at which the fluid is to be pumped must be estimated. The initial design conditions were estimated to be 100,000 BWPD at 1200 psi discharge pressure. The ultimate conditions were estimated to be 150,000 BWPD at 2000 psi discharge pressure. With these discharge volumes and pressures established, an economic study of the 2 different types of pumps can be made. There are many factors that influence the selection of high pressure water injection pumps. The most important of these are as follows: (1) environment; (2) choice of prime movers; (3) flexibility of operation; (4) pump efficiencies; (5) space requirements; (6) operating and maintenance expense; (7) installation cost; (8) initial pump cost, and (9) expected life of injection plant.

Most E&P companies or departments in the petroleum industry face significant compression in resources

Multi-staging a well with more than one plunger utilizes more of the well's energy to lift fluid. Setting a Multi-stage tool in a well with a collar stop or tubing stop allows for one plunger to lift below the tool and one plunger to lift above the tool. By staging the well with a multi-stage tool, the fluid load on each plunger is lifted to a shallower depth. The bottom plunger lifts fluid to the tool which is caught with a standing valve. The second plunger then lifts that fluid to the surface. All of the head gas above the liquid level is sellable gas, but is wasted energy. By staging the well, part of the head gas can be used as an energy lifting source. The multi-stage tool can be used in many different types of wells.

A common problem in small, mature fields is the limited and poor quality data, typically consisting of only old logs and production history. The objective of this work is to demonstrate practical applications for processing and analyzing the limited information. The Round Tank (Queen) reservoir in Southeast, New Mexico was selected as a case study. Old logs, 14 modern logs and one-core are the main sources for this reservoir study. The results from modern-log analysis will be used to support the results obtained from the old logs. Normalization of old neutron logs and calibration of old sonic logs were two techniques applied to acquire valuable information. As a result the mineralogy, porosity and productive thickness of the Queen were determined. A newly discovered friable sand bed was identified and has implications on stimulation and reservoir performance. The reservoir characterization can be further used for field optimization or EOR project.

The Beam Gas Compressor (BGC) utilizes the energy from the normal pumping action of the pump jack. Gas is drawn from the casing during the suction cycle through check valves and is pumped (compressed) through check valves into the flow line on the compression cycle of the unit. The gas flows with liquids to the separator and to the gas sales line. The BGC is a double-acting unit and compresses gas on both the up and down stroke of the pumping unit. The BGC does not affect the counterblance of the pumping unit. The BGC has been successful in increasing production and cash flow on low bottom hole pressure wells where a rod pump is being utilized to produce the fluids. By relieving casing back presssure we experience an increase in both gas and oil.

The presented trend toward lease consolidation and automation, which is a result of economic influence, has prompted a re-evaluation of the method and design for central treating of oil field emulsions. This is largely the result of having to handle and treat larger volumes of fluid, but is also due to the need for a more efficient and automated type operation. If the operator is to increase his income, assuming a fixed volume allowable, he must accomplish it by either reducing the cost of his operation, or improving the value of his product, or both. Such are the possibilities of the Chemelectric Treater. The Chemelectric has in almost every case reduced the cost of operation over that of conventional emulsion treating, and in some cases has even increased the value of the salable crude product. This method of treating simply combines the principle of electrical coalescing treatment with the age old principle of thermo-chemical treatment. Another factor in the increased use of the electrical coalescers has been the improvement in availability of electrical power throughout the oil field.

The hydraulic pump is a highly sophisticated means of artificial lift which has grown in popularity in recent years. This popularity combined with usage in diversified production fluids has led to several production problems that are very expensive to the operator. Though mechanical devices have been developed to limit production fluid problems, other corrosion causing problems in production fluids must be controlled by other means. The chemical industry is quite involved in research and product testing to aid in combating these outside problems. Chemicals are on today's market that will greatly aid in hydraulic pump performance, particularly if the proper analytical data, product selection, and application procedures are used.

Scale has been a major problem in producing wells practically as long as water has been produced along with oil and gas. At the present time, thousands of wells in the Permian Basin are being treated to combat this scale problem. The purpose of this paper is to acquaint the field operating personnel with some of the reasons why scale is formed, the chemicals which have been used in the past for scale treatment, and the chemicals which have been recently developed. Also, a good portion of the discussion is devoted to the results of the use of these newly developed chemicals. Because of the limitation of time, this paper does not include remedial type treatments such as acid treatment of carbonate scale, or acid and certain additives for treatment of sulfate scales. Possibly this subject can be covered at a later date.

Corrosive effect of chemicals on steel was the primary reason the oil industry began searching for an alternative material for sucker rods. This study is not a comprehensive study of chemical corrosion inhibitors, but it will discuss chemical corrosion and its effects on steel sucker rods and fiberglass sucker rods. Steel sucker rod replacement due to corrosion is one of the major costs of oil production. The author will show that water/C02 and sour (H2S) gas has no obvious detrimental effect on a fiberglass rod body.

Environmental stewardship involves not only responsible use of chemicals and materials during drilling and completions, but also includes a thorough understanding potential health and environmental hazard posed by chemicals used in these processes. Recent focus on potential hazards associated with chemicals used in oil and gas production has expanded to include not only chemicals used in treatments such as hydraulic fracturing, but to other applications including cementing and drill fluids. Global focus on chemical disclosure and increased attention on chemicals covered by trade secret protection is driving the industry to assess products used in production processes and consider viable alternatives to address public and regulatory concerns while encouraging products innovation to reduce environmental or human risk. A comprehensive review of products and their components using a scientifically based methodology is fundamental to the identification of potentially unacceptable hazards and can support efforts in product reformulation, where applicable, to produce an efficient and compatible product that may pose fewer or less severe health and environmental hazards.
This paper discusses the aspects of a Chemical Evaluation Process Review (CEPR) that examines products on a component level for various environmental and health hazards in accordance to regulatory standards on a global scale by considering: the presence/absence of specified substances; the likelihood of a product passing a comprehensive OSPAR screen; screening of substances for regulatory lists globally; and a detailed review of environmental, toxicological and physical hazards. In addition this paper will present expansion of the CEPR beyond hydraulic fracturing products as well as acceptance by the industry of environmentally preferred alternative products.

Interest in reservoir stimulation by chemical explosive fracturing is gaining momentum in the petroleum and natural gas industry. This paper discusses the present "state-of-the-art" of explosive fracturing. Characteristics of the three types of explosive products, solid, liquid, and slurry and their specific application to formation fracturing are reported. Explosive loading, displacement, and initiation techniques presently employed in the field are included. Test results from more than 30 field applications using the various explosive products will be reviewed. Field tests to date have been conducted at depths ranging from 40 ft to 7000 ft, using explosive quantities from less than 100 lb to 35,000 lb. Finally, engineering criteria to be used in selecting a well candidate and designing a field application will be discussed.

A chemical gel has been developed to plug leaks in injection wells to provide effective zone isolation and casing protection. Since it is a gel material, the sealant can easily be removed from the casing-tubing annulus for workover operations. This chemical forms a thick gel after placement in seal casing leaks, (2) protect fresh water aquifers from the annulus which helps (1) steel casing from corrosion, and (4) can be removed from contamination, (3) protect the casing-tubing annulus by rotating and reciprocating the tubing and washing out. Chemicals used in this process are nontoxic and are compatible with fresh water aquifers. Field case histories are presented to show operational procedures and injection pressures before and after treatment and to illustrate effectiveness of the treatment.

As with all EOR techniques, the injection of carbon dioxide into oil bearing reservoirs causes fundamental changes in the chemical and thermodynamic properties of the reservoir fluids, not only as they exist in the reservoir, but also as they are produced. Additionally, because of the dynamic nature of CO2 flooding, the produced fluids (gas, oil and water) will change continually as various areas are swept and produced. Thus, producing wells, satellites and production batteries will experience constantly changing fluid conditions throughout the life of the project. Although various portions of the production system can approximate equilibrium, change is inevitable. Given these conditions, chemical programs used in production operations must be designed with flexibility in mind. Chemical treatments must accommodate
produced fluids whose tendencies to deposit scale, corrode steel, deposit paraffin and form emulsions are changing. This paper will address changes that must be made to transform traditional production chemical programs into systems that can maintain the efficient production in CO2 enhanced recovery.

Emulsions in oil production are accepted today as a normal operational condition. The equipment and materials necessary to resolve produced emulsions are usually placed in the field as soon as a well begins to produce water in the form of an emulsion in quantities that exceed pipeline specifications. During the early years of the oil industry neither the knowledge, equipment, nor chemicals were available to treat oil effectively. Early methods of breaking emulsions consisted of settling time, and, in some cases, the use of heat. As a result, emulsion was often drawn off the bottom of tanks and burned as waste.

When Colonel Drake drilled the first oil well in this country he was extremely fortunate in two ways; one, he discovered at a very shallow depth, as compared with present day footages; two, the oil he discovered was a paraffinic, golden colored crude which contained very few impurities. It was easily refined with simple equipment, and required no treatment in the field. The development of problems and their solutions, which are connected with the production of oil, have been gradual.

Paraffin deposition during the production and transportation of hydrocarbons prior to refining represents a very real and costly problem. New inroads for chemical treatment have been made during the past few years. These developments have led to a program of preventive chemical treatments which offers a viable alternative to hot oiling or other mechanical remedies for paraffin control. This paper discusses the design of a paraffin treating program using a batch method of application. Topics investigated are sample identification and characterization, paraffin compound testing, program design, chemical application, field performance evaluation, and program adjustments. These topics are presented for practical application.

A basic discussion of an electrical-chemical dehydration process for breaking oil-water emulsions by passing these emulsions through an electric field.

Choice of plunger type may be as critical as the surface equipment to optimize a plunger lift well. When considering plunger lift candidate's decline, IPR, velocity, fluid and pressure are used to build a proper evaluation. The necessity for proper plunger lift choice in completely optimizing a plunger well can result in incremental production from an existing plunger system by as much as 500 Mcf/day by changing from a conventional plunger lift system to a high speed bypass plunger. However, a bypass plunger in a well with the wrong conditions will not result in a successful increase and may in fact hurt production. In order to properly evaluate wells it is necessary to consider the velocity and the fluid rates for high speed bypass then change to consider more conventional methods. This paper will discuss the well evaluation process as it pertains to plunger lift applications.

Many papers have been written concerning the planning and design of fracturing treatments. Most have involved proposed production increases, fracture conductivity, fluid coefficient and fracture area. This paper will delve into the simple mathematics of cost of fracturing fluids. A total cost comparison of water versus oil based on the general treatment of each fluid, horsepower requirements at equal rates, and fracture area per dollar are presented. Lease crude, refined oil, commercial brine, fresh water and a 40-60 mixture of brine and freshwater will be considered.