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The Federal Government released a new requirement under the Occupational Safety and Health Administration Standards on May 26, 1992. This code for process safety management was issued under 29 CFR 1910.119 in the Federal Register. The code contains requirements for preventing or minimizing the probability and consequences of catastrophic releases of toxic, flammable or explosive chemicals. Oil production and processing facilities which have processes involving more than 10,000 lbs of flammable liquids or gases and which are "normally manned" are covered under this code.

Contrary to present-day methods, this machine operates a sucker rod system at a constant velocity through approximately 80 per cent of the stroking cycle, the balance of the cycle being used to halt the motion and reverse the direction. The reversal action of this machine is accomplished with out the aid of power. To effect the reversal, it utilizes some of the energy put into the system during the constant velocity portion of the stroke. The method of accomplishing this non-power reversal will be fully explained as well as all other engineering features of the equipment.

Conoco trains engineers and waterflood operators in their on-going waterflood school. It is in this school that waterflood problems are presented and resolved. This presentation concentrates on waterflood operational problems, discussed in this school, such as: preventive maintenance, problem producing wells, flowline problems, corrosion, tubing, polished rods, casing, produced water clean-up, waterflood station vessels, and injection pumps and meters.

This paper deals with the development of a mathematical model to describe the miscible displacement of drilling muds by cement slurries under laminar flow conditions. The model accounts for the effects of differing properties, geometry, and displacement rates. The model assumes that "mixing" in the displacement zone by molecular diffusion is minimal, and uses the Robertson-Stiff model to describe the rheological properties of both the drilling fluid and the cement slurry.

The prime consideration of an operator after the pumping unit has been installed is how to obtain the longest possible operating life, the minimum amount of nonproductive time, and the lowest overall operating cost. This problem is most easily solved by an understanding of the basic operation of the unit and the requirements of maintenance.

Although membrane separation is perceived as new technology, membrane based CO, removal has been commercially practiced for more than 15 years. The first commercial membrane based CO, removai system was the SACROC facility in west Texas. The system was commissioned in 1983. Over several expansions, the capacity of the facility has quadrupled and continues to provide a cost effective solution. This installation represents a true success story for membranes.

Stuffing boxes on beam pumped wells have always required a high level of maintenance even though operators and manufacturers have constantly searched for ways to improve their performance. Essentially no documented research has been developed on which to base performance enhancing designs. It is the purpose of this paper to offer two new concepts which could benefit stui"fing box performance. Steel and rubber are known to be among the worst combinations of materials for applications where a low coefficient of friction is important.

First, we have established that it is a necessity to meter fluids if we are to transfer fluids to their eventual consumer, so it makes little difference here whether this phase of metering is profitable or not. The only question here is one of method. That is, which method is the least expensive and results in the least waste. This is the argument now in question concerning lease automatic custody transfer and conventional crude handling facilities.

A study of stimulation techniques in the Morrow and Atoka formations was conducted because operators wanted to find a way to slow the anomalous decline in production from wells that were drilled and completed during the late 1970s and early 1980s. Operators investigated completion practices used during this period and conducted pressure-transient analysis. They analyzed sidewall cores for mineralogy studies of the reservoir rock and sensitivity testing of water and acids. From this study, we concluded that the completion fluids used were damaging the reservoir rock.

Paper addresses conformance problems with dominating eroded interwell communications to offset producers in certain patterns of the SACROC Unit Carbon Dioxide Enhanced Oil Recovery (CO2 EOR) Project in Scurry County, Texas. The opportunity to maintain optimum pressure support and desired mobility of the hydrocarbons in various patterns and areas was being lost. Various technologies and methods were investigated and/or deployed in attempts to redistribute CO2 injection into desired intervals and reduce the wasted cycling.

In the past decade the number of secondary recovery projects has increased rapidly in the Permian Basin and surrounding area. Water injection is the most popular method of re-energizing reservoirs. As a result, demands on the artificial lift equipment have increased due to higher individual well productivity. In many instances larger equipment has been installed. Two major reasons for replacing beam equipment in the past have been torque limitations and displacement limitations. Torque limits are usually reached prematurely because the unit is being operated in the longest stroke.

The necessity and desirability of well stimulation has been apparent for many years. Many wells and fields would not be economical producers without modern completion and stimulation methods. To break this situation down even further, it can be said that where several porous zones are present in a well, each zone will not contribute its maximum production without proper treatment. With these things in mind, our purpose becomes very clear. It is simply to properly stimulate each porous zone or stringer in the pay section. A number of methods have been employed to achieve this selectivity.

Pump design, material selection, and corrosion protection are presented as parameters in the selection of sub-surface pumps where pump usage is in a corrosive environment.

For CO2 flood modeling the complex geology at the Pennsylvanian SACROC Unit, new core was obtained by utilizing several new techniques to preserve key features or provide adequate detail on the analysis, including analysis of twelve-inch whole core samples. To maximize the value of new core data for model development and scale-up exercises, a "scale down" exercise was performed on selected samples: twelve inch whole core samples were analyzed then cut into six inch whole cores, two inch whole cores, and selectively plugged.

Conventional downhole treatments for scale and corrosion typically rely upon either "squeeze" or batch type treatments for control of corrosion and/or scale. These treatments introduce large amounts of inhibitor into the wellbore area and may adversely affect the production characteristics of the well, require excessive amounts of chemical, and require repeated treatments over short periods of time. The use of encapsulated materials for scale and corrosion inhibition has recently been shown to be a reliable and economic alternative to the conventional squeeze or truck batch treatment.

A standard fracturing blender retrofitted with a microprocessor controlled proppant delivery system has been operating in the Odessa, Texas area since May 15, 1986. The speed and control capabilities of the system's microprocessor has allowed fracturing operations incorporating non-standard "ramping" sand concentration schedules to be routinely performed with this blender. Fracturing operations with "stair step" sand concentration schedules have also been completed with this blender.

Through the more precise control of the existing laws of physics comes the improvement in efficeincy, and as it follows, his surroundings, his possessions, and inevitably, his future. It is our challenge in this time of falling oil prices, shakey economy, and expected world-wide surprises that we exist. If we could individually improve each of the conditions that shape our future, we would certainly make attempts in that direction. Yet, being only mortals,. (even Arkansas mortals) we must religate our lives to the improvements that we can achieve.

Operators drilling in the Permian Basin and surrounding areas with low fracture gradients have long strived to achieve zonal isolation and prevent losses in primary cementing. Solutions generally involved two-stage cementing, water extended lightweight filler cement or foamed cements. Microsphere based cement provides additional solutions to problems associated with low fracture gradients.

The Mini Massive Frac is a technique designed for stimulating low porosity, low permeability formations. It allows for placing high concentrations of sand in the hydraulically induced fracture by limiting fluid loss. The technique also utilizes crosslinked polysaccharide derivative fracturing fluids to provide a uniform distribution of proppant. Since its' introduction to the Permian Basin, the Mini Massive Frac has been used to treat more than 150 wells, with considerable success. This paper describes the design characteristics of the Mini Massive Frac technique.

Repairing tubing leaks can easily result in the most expensive operating cost incurred in rod pumped wells. Tubing leak repairs are not only expensive but lost revenue from downtime can be significant. The prevention of tubing failures will greatly enhance operating profits from a rod pumping system. This paper will discuss rod buckling, which is one common cause of tubing failures, and how to minimize this problem by adjusting pumping parameters and installing a designed sinker bar section.

Equipment failure and it's attendant costs are extremely important in today's petroleum industry. Since Rod Pumping is the predominant means of artificial lift, minimizing equipment failure in rod pumped wells can have a significant impact on profitability. This paper addresses recommendations which have proven successful in the majority of wells. These have been developed within ARC0 over the past 25 years and include equipment selection and design, operation and chemical treatment. The ultimate goal is to address and solve problems on a well by well basis.

Performance predictions of the proposed miscible CO2 injection project for the Wellman Field, Terry County, Texas were made using an enhanced oil recovery process numerical simulator. The study investigated the potential of injecting a relatively small, gravity stable CO2 slug with nitrogen as the drive gas into the crest of the cone-shaped reservoir. The effects of slug size, injection rate and reservoir pressure were evaluated for an optimum future operating plan.

Primary oil recovery frequently results in oil recoveries of only 10 to 20 percent of the original oil in place. Several hydrocarbon miscible methods have been tested and proven successful as a secondary or tertiary method of oil recovery under certain reservoir conditions."2"3 Wide application of these methods has been limited by economic factors.

The world's first large-scale miscible displacement project by high-pressure gas injection has produced 130,000,000 bbl, almost double the original estimated primary recovery of 69,000,OOO bbl, at the University Block 31 field in Crane County, Tex. Early injection-production history is shown on Fig. 1. The field-wide project began in 1952, and will keep the unit on stream well into the future, with ultimate recovery efficiency estimated at 60%. Infill drilling has helped boost daily production to 16,000 bbl, highest producing rate since gas injection began in 1949.

Gas breakthrough can be a considerable problem in C02 flooding. From initially causing severe operational handling conditions to ultimately losing otherwise recoverable hydrocarbon reserves, industry personnel devote multiple resources, including time and money, to combat it. Maintaining injection below parting pressure is one effective method to minimize premature breakthrough in offset producing wells. Determining fracture gradient on an individual well basis in a periodic manner and adhering to the resultant rate and pressure parameters has aided the SACROC Unit's reservoir management.