API Crude Oil Research Articles

Zeolite and clay-mineral induced resistivity in simulated reservoir sand

Clay-minerals dispersed in reservoir sands affect electric log response and register reduced resistivity values. Natural zeolites however, with large microporosities and water content could have a greater affect on resistivity measurements. Resistivity values were measured on a series of artificial cores prepared by mixing and compacting various percentages each of clinoptilolite, smectite and illite, with a medium-grained, moderately sorted quartz sand. Various concentrations of NaCl solution mixed with 39 API crude oil were circulated through each core. Impedance measurements were taken, resistance values segregated, and resistivities determined for each core. Water saturation values were calculated from the empirical resistivity values and porosities using a modified Simandoux equation. These values appeared to be much higher for those cores which contained the zeolite clinoptilolite. Clinoptilolite, when dispersed in a simulated reservoir sand and treated as a dispersed smectite or illite, produced inflated saturation values. This inflation effect is thought to be due to the more extensive microporosity and larger micropore water content of the zeolite. Therefore, from the empirical aspect, resistivity measurements of reservoir sands containing a dispersed zeolite, rather than a clay-mineral, would probably yield misleading water saturation values.

Utilization of Current Geological, Geophysical, and Engineering Technologies to Increase Oil Recovery in the Suffield J Pool, Alberta, Canada: ABSTRACT

The Suffield upper Mannville J pool, discovered in 1977, contained original oil in place of 90 million bbl of 14{degree} API crude oil, with less than 1% originally estimated to be recoverable through primary depletion. The pool is approximately 5 mi long and 0.5 mi wide. The pool is part of a much longer, lenticular sand body interpreted to be an estuarine sand shoal, and it has up to 135 ft of pay at depths of about 3,000 ft. The geometry and reservoir geology of the pool, together with the high viscosity of the oil, have encouraged the piloting and implementing of a number of techniques to improve oil recovery and reduce development costs. These techniques include reduced well spacing, horizontal drilling, a hot-water flooding pilot project, and development of a gas injection process to reduce water coning. The pool initially was developed on a 40-ac spacing. The spacing was reduced to 2.5 ac by an infill drilling program based on three-dimensional seismic. In 1988, two horizontal wells were drilled to determine if the remaining reserves could be more economically recovered than by using vertical drilling, minimizing water coning at the same time. Integrated geological and three-dimensional seismic interpretations weremore » successful in guiding horizontal wells along the top of the porosity and away from shale-filled intrabar channels. Detailed review and interpretation of data from cores and logs, together with production histories of individual wells, indicated that a number of earlier wells were perforated in ineffective parts of the reservoir. A subsequent program of recompletions significantly enhanced production rates. These projects required the complete integration of geological, geophysical, engineering, and drilling technologies. The techniques used have significantly increased the expected oil recovery to more than 10% of the oil in place and the potential for an even greater recovery has been established.« less

An Electrically Heated Buried Gathering System Transports High-Pour-Point Crude Oil

This paper describes two electrical heating systems that are being used successfully on buried flowlines transporting crude oil with 70 to 90 degrees F pour points. The electrical systems, insulation, and protective outer jackets are discussed. Installation and operating costs and problems also are presented. Introduction The Dickinson Heath Sand Unit (DHSU) is located about 1 mile north and 1 mile west of Dickinson, N.D. (Fig. 1). This unit has 37 producing wells, one water well, and 14 injection wells located in 26 sections, The wells are completed in the Heath sand at 7,900 to 8,100 ft and produce 33 to 35 degrees API crude oil with pour points produce 33 to 35 degrees API crude oil with pour points of 70 to 90 degrees F. A waterflood began in Dec. 1973. Production has not peaked. The unit produced 4,409 BOPD and 4,600 peaked. The unit produced 4,409 BOPD and 4,600 BWPD with water injection rates of 9,800 B/D during June 1977. Before unitization, each well had its own tank battery. The heater treaters were located about 120 to 200 ft from the wellhead. Even with these short flowlines, pressures of more than 2,000 psi sometimes were needed to displace the congealed crude oil. After the waterflood began, a water gathering system was necessary. Because this system would cost %1,300,000, a total produced-fluids gathering system with one central battery was economically attractive. Therefore, many methods of transporting the high-pour-point crude oil were investigated and evaluated. However, most methods were either too expensive or the flowlines would be plugged after a long shutdown. The only way to remove the congealed oil would be to install pump-out risers about every 200 to 500 ft and displace the oil with hot water under high pressure. Two methods for electrically heat-tracing insulated lines were found that appeared feasible for the gathering system. These were the Skin Effect Current Tracing (SECT) and the Thermon systems. It was decided to test these systems on four lines in 1974. The SECT System Principle Principle The SECT heating element used in our system is a 1/2-in. Schedule 40, black iron pipe that is welded to the carrier pipe. The welds are spaced evenly the entire length of the pipe. The welds are spaced evenly the entire length of the carrier pipe with 2-in. passes separated by 2-in. open spaces. The welding attaches the heating element (or "heat tube") to the pipe and provides a heat path to the pipe. A single, insulated copper wire passes through the pipe. A single, insulated copper wire passes through the center of the heat tube and is connected to the heat tube at the far end (Fig. 2). Alternating electric current flows through the wire and the heat tube and creates heat by the resistive loss of the well known I2R principle (Joule's law). The magnetic fluxes surrounding the current in both the tube wall and the wire concentrate in the inner wall of the heat tube because of the high magnetic permeability of mild steel. The interaction of these two fluxes creates the "skin effect" that causes the current in the heat-tube wall to concentrate near the inner surface (0.005 in.) and be essentially nonexistent at the outer surface. JPT P. 890

Forecast of Domestic Crude Oil Prices

In early 1973 it was forecast that domestic crude oil prices would increase sharply between 1972 and 1980. Gulf Coast 34 degrees API crude oil was projected to rise from a 1972 price of $3.63 per barrel to a 1980 high of projected to rise from a 1972 price of $3.63 per barrel to a 1980 high of $6.10. By the end of 1973 it was clear that the forces of change were much stronger than expected. 1980 had, in effect, already arrived! Introduction The decade of the 1960's was characterized by highly stable crude oil prices in the U. S. From 1969 to date (Feb. 1973), there have been a great number of physical, economic, ecological, and political developments bearing importantly on the political developments bearing importantly on the future level of crude oil prices. (See Table 1.) The purpose of this paper is to provide a systematic analysis of the probable impacts of these factors on the trend of domestic crude oil prices over the remainder of this decade. Although the forces of change have been strong during the past 4 years, their net effect on domestic crude oil prices was modest (Fig. 1). Indeed, over the past 15 years, the pattern of these prices has resembled a shallow saucer. Since 1969, average prices have advanced 31 cents/bbl equivalent to a prices have advanced 31 cents/bbl equivalent to a 3 percent annual growth rate to reach a level of $3.40/bbl in 1972. Virtually all of this increase, however, was needed to offset the increased tax burden imposed by the Tax Reform Act of 1969. With investment and operating costs rising throughout the past 15 year, there has been a general downtrend in the unit profitability of domestic crude oil production. Looking ahead, I arrive at the general thesis that the pattern of domestic crude oil prices in the remaining years of the 1970's will differ sharply from that of the past. I expect strong upward trends in prices. The lower prices of these prices will tend prices. The lower prices of these prices will tend to be established, as in the past, by the landed costs of foreign crude oil, and the upper limits will tend to be set by the prices needed to provide adequate incentives for vigorous exploration for and development of new domestic supplies, including both conventional petroleum and synthetic fuels. Most of this paper will be devoted to a discussion of me possible trends in prices associated with these outer limits and to a brief comment on other factors that will influence the timing and magnitude of price changes. World Petroleum Supply and Demand The single most important determinant of future domestic crude oil prices will be the landed cost of foreign crude oil. Before hazarding a projection of these future costs, some comments are needed on the outlook for world petroleum liquids supply and demand. First, from the viewpoint of world petroleum reserves, it is evident that these are petroleum reserves, it is evident that these are sufficiently abundant to meet potential requirements through 1980 (Fig. 2). If there should be any physical shortages of crude oil during this period, they will be man-made. Some people, in looking at the high ratio of reserves to current production, conclude that fundamental economic forces should lead to a downward trend in prices. I would note, however, that reserves as such do not constitute potential supples those reserves must first be developed and tied into appropriate transportation facilities. The investment programs required to transform reserves into productive capacity are discretionary and will depend, among other things, on the merits of alternative patterns of production. JPT P. 135

A HOT WATER FLUIDIZATION PROCESS FOR CLEANING OIL-CONTAMINATED BEACH SAND

ABSTRACT A pilot device capable of cleaning one ton per hour of oil-contaminated beach sand was built and tested. The processing scheme was a variation of the hot water method used in the Athabasca Tar Sand Deposits and utilized liquid fluidization to effect the oil-sand separation. Tests performed with a sand mixture containing 1 to 2 percent of a 23° API crude oil showed that upwards of 95 percent of the oil could be removed. Operation with a 14° API residual oil was less satisfactory. The hot water fluidization process is judged to be a technically feasible concept although there appear to be definite limitations as to its general applicability. These limitations are concerned primarily with the range of sand particle sizes that can be fluidized without excessive elutriation. Additional experimentation is needed to further delineate the range of potential application.

Water Injection in the Lower Jones Sands, Huntington Beach Offshore Field

Abstract The Lower Jones is an unconsolidated, multiple-sand reservoir several hundred feet thick, containing a 14 to 19 deg. API crude oil. However, the sand thickness and unfavorable mobility ratios caused by the viscous crude have not deterred a successful waterflood project. Oil production has approximately tripled since the flood started in Nov., 1963. The reservoir is broken up by an extremely complex faulting system. The effect of these faults, with displacements ranging from 10 to 75 ft, is so significant that the over-all project must be handled as 17 individual fault block floods. Both crestal and downdip injectors were utilized early in the life of the waterflood, but the unfavorable effects of crestal injection, as noted in injector profile surveys and crestal producer performance, caused the oil production to decline and the water-ail ratio to increase prematurely. A shift to flank injection in most of the fault blocks stopped the decline and the excessive rate of water- cut increase. Sand control, which is essential in the Lower Jones, is achieved by installing gravel flow-packed liners in both the injectors and producers. Drift angles of 75 deg. or more are required in individual wells to reach some of the more remote locations in the reservoir. The flow pack is accomplished by dropping the drift angle through the productive interval to 45 deg. or less. The production and injection history of the project through July, 1967, is presented to show the results being achieved. Introduction The Huntington Beach oil field is situated 41 miles southeast of Los Angeles on a high point on the coastal fold close to the south edge of the Los Angeles basin in Orange County, Calif. Location of the Huntington Beach field with respect to other fields in the Los Angeles basin is shown in Fig. 1. The offshore Jones pool lies in a westerly plunging anticline on the extreme west side of the field. The heavily faulted reservoir is composed of a 700-ft section of continuous Upper Miocene unconsolidated sands separated by shales containing interbedded sand stringers. The productive thickness ranges from 350 to 400 ft. A typical electric log of the productive interval is shown in Fig. 2. The most significant shale is found near the middle of the section at the electric log marker AG. The sands above the AG marker are known as Upper Jones (Div. A of the Upper Miocene) while the sands below the AG2 marker are called Lower Jones (Div. B of the Upper Miocene). Productive area of the Lower Jones under Signal Oil and Gas Co.'s leases in the offshore field covers more than 770 acres. The primary recovery efficiency of the Jones zone was quite low due to the high viscosity of the crude oil and the lack of sufficient natural pressure maintenance. Ultimate recovery under normal depletion, supplemented by such programs as gas-oil ratio control, a limited gas injection project and redrilling of idle producers, was estimated to be 20 percent of the original oil in place. In 1959 a pilot waterflood project was started in the sands between the AK and AL markers in the Lower Jones to determine if water injection would be a satisfactory method to improve recovery performance. Results of the pilot test, which ended in early 1961, were so encouraging that planning began immediately to extend waterflood operations to the entire reservoir. The first phase of the full-scale Lower Jones waterflood began in Nov., 1963, and injection was expanded to most areas of the reservoir by Sept., 1965. This article discusses the performance of waterflooding activities and highlights some of the unusual problems encountered during the early life of this unique offshore waterflood project. JPT P. 127ˆ