Reef Reservoirs Research Articles

Reinjection of Large Volumes of Produced Water in Secondary Operations

Abstract A study was made of the operating performance histories of a pressure-maintenance and four waterflood projects in the Permian Basin area, where large volumes of produced water have been reinjected into the producing formations. The projects reviewed include a wide range of characteristics: open and closed water systems, volumes of reinjected water froth 2,200 to 12,500 B/D, sand and limestone formations, depths of 1.300 to 6,750 ft. average permeabilities from 17 to 275 md, bare and protected facilities, and 10- to 50-year project life. Each project exhibited performance data which indicated that reinjection of large volumes of produced water provides a good source of injection fluid, results in practical and prudent salt water disposal and, in many cases, results in conservation of fresh water for future domestic needs. Introduction The increasing difficulty of finding adequate new oil reserves has caused almost every field in West Texas to be reviewed for possible secondary recovery applications. Because most secondary recovery processes use water, the availability and prudent utilization of water are very important to all oil operators. Standard Oil Co. of Texas' production operations in West Texas include numerous water floods, and several of these projects are reviewed and discussed in this paper. The case histories presented cover handling and reinjecting large volumes of produced water. The fields presented, as shown in Fig. 1. include SACROC unit, Howard-Glasscock, North Ward-Estes. Keystone-Colby sand, and South Ward. The combined cumulative primary and waterflood recovery of these fields to Jan., 1965. is 878.8 million bbl. Pertinent reservoir and waterflood data for the Standard of Texas' projects in each field are shown in Tables 1 and 2. Equipment used and materials for construction in each injection system are shown in Table 3. Waterflood performance histories are shown in Figs. 2 through 7. Schematic flow diagrams of the injection systems are shown in Figs. 9 through 13. SACROC Unit History and Development The Canyon Reef reservoir of the Kelly-Snyder field in Scurry County was discovered in Nov., 1948. The field now encompasses some 50,000 productive acres and 1,321 wells. Cumulative field recovery to Jan., 1965, is 322.4 million bbl. The reef, a limestone formation, is a low mound-type structure varying In thickness from 0 to 800 ft. The field was essentially developed by 1951; and, after extensive negotiations, the field was unitized with a unit manager and three segments, each operated by a working-interest owner effective March, 1953. Standard of Texas was designated unit operator on May 1, 1962. JPT P. 781ˆ

Consolidation and LACT in the SACROC Unit

Abstract Installation of full-scale consolidation and lease automatic-custody-transfer oil delivery stations was commenced in the SACROC unit during 1957. By Feb., 1963, all the 42,000 BOPD production was being delivered through 12 LACT units. Equipment used in the LACT installations is of varied manufacture and design. Oil deliveries through the LACT units range from approximately 1,000 BID at the smallest station to 12,000 BID at the largest. Both dump-tank meters and positive displacement meters are used. History of the development of the SACROC unit consolidation and LACT program and the operating experience for the various types of installations are presented. Introduction The Kelly-Snyder field, Scurry County, Tex., was discovered in Nov., 1948. The producing formation, the Canyon Reef limestone, lies at a depth of about 6,600 to 6,900 ft. Development of the field proceeded at a rapid pace until it was essentially completed by the end of 1953. The field now contains 1,316 wells overlying approximately 52,000 oil-productive acres. In Dec., 1950, the Scurry Area Canyon Reef Operators Committee was formed, this name later being abbreviated to SACROC, and unitization studies were begun in Jan., 1951. Unitization of the major portion of the field became a reality on March 1, 1953, when SACROC unit began operation. The unit now contains 1,256 wells and approximately 50,000 productive acres, which overlie about 99 per cent of the productive formation of the Kelly-Snyder field. Initially, the operation of SACROC was under the supervision of a Unit Manager's Office, and the field was divided into three segments, each operated by one of the working interest owners-Standard Oil Co. of Texas, Mobil Oil Co. and Sun Oil Co. On May 1, 1962, after amendment and ratification of the Unit Operating Agreement, Standard Oil Co. of Texas became the unit operator. At the time SACROC became effective in 1953, there were approximately 400 active tank batteries within the area of the Kelly-Snyder field operated by the unit. Unitization made it possible to consider extensive tank-battery consolidation. By 1957 pressure-maintenance operations had resulted in stabilized producing conditions. Facilities had been installed to collect and return all produced water to the Canyon reef reservoir. Some consolidation work on a small scale had been done in the unit prior to 1957 as it became desirable to combine manifolds because of water line extensions and other field operating conditions. During the latter part of 1957 a full-scale program of consolidation of producing facilities and installation of automatic custody transfer equipment was commenced in SACROC unit. By Feb., 1963, all the 42,000 BOPD production from unit wells was collected into 12 central batteries and was being delivered to five pipeline companies through automatic-custody-transfer units. Experience in the unit has shown that it is economically feasible to replace conventional producing facilities with automatic-custody-transfer equipment in a developed field. In addition to improving operating efficiency, the centralization of producing facilities into large central batteries has made it economically feasible to collect and sell tank vapors which previously would have been vented to the atmosphere. Delivery of oil through LACT units has virtually eliminated breathing and filling losses which occurred in normal storage of oil in stock tanks without vapor control. As a result of the LACT installations, the amount of oil stored, closing stock, above ground in the unit has been reduced from approximately 160,000 bbl in March, 1957, to approximately 47,000 bbl since March, 1963.Representatives of a number of the working interest owners in SACROC contributed to the planning of the consolidation and LACT program. Early work and planning were done at a time when automatic custody transfer of oil was in the early stages of development. The five pipeline companies which gather unit oil have furnished assistance and have been very cooperative throughout the development of the consolidation and LACT work. Both dump-tank type units and PD meters have been installed and operated. LACT units are now operated which handle approximately 1,000 BOPD at the smallest station to 12,000 BOPD at the largest. The purpose of this paper is to discuss the development of the consolidation and LACT program in the unit, to describe the equipment used, and to discuss the results obtained from the program. JPT P. 751ˆ

Paleoecology of Devonian Swan Hills Reef, Alberta, Canada: ABSTRACT

The Limestone reef reservoir at Swan Hills consists essentially of a buildup of successively smaller atoll-like layers. Precipitation of calcium carbonate within the lagoonal area of each layer essentially kept pace with growth of the outer organic lattice. Within the reef mass, six depositional environments characterized by specific suites of fossils (or fossil fragments) and associated limestone textures are recognized as follows. 1. Aerated moderately agitated water of normal marine salinity (widespread shelf or submerged reef-built platform). Thamnopora-type corals, Amphipora, stromatoporoids, crinoids, articulate brachiopods, rare rugose cup corals, and ostracods occur in light gray-buff skeletal microgranular limestone of low permeability. 2. Semi-stagnant quiet water of normal marine salinity (leeward side of reef). Crinoids, articulate brachiopods, rare thamnopora-type corals, Amphipora, pancake and bulbous stromatoporoids, rugose cup corals, ostracods, and gastropods occur in impermeable dark brown argillaceous skeletal calcilutite with thin black bituminous shale beds and rare dark chert nodules. 3. Aerated highly agitated water of normal marine salinity (organic lattice). Light buff stromatoporoid bulbs and Amphipora, rare thamnopora-type corals, rugose cup corals, crinoids, and articulate brachiopods form permeable patch reefs and interbedded skeletal calcirudites. 4. Semi-stagnant quiet marine water of slightly increased salinity (partly restricted shelf). Dark gray biostromal buildups of stromatoporoid bulbs and minor Amphipora occur in impermeable black shaly matrix. 5. Aerated, quiet to highly agitated marine water of increased salinity (mud flats, tidal channels, and shoals within atoll-lagoon). Amphipora, rare ostracods and gastropods occur in light buff impermeable to highly permeable precipitated limestone (lithographic, microgranular, pseudo-oolitic, and intra-formational conglomerate). 6. Semi-stagnant quiet marine water of increased salinity (deeper protected pools in atoll-lagoon). Amphipora, rare stromatoporoid bulbs and ostracods occur in impermeable dark brown slightly argillaceous calcilutite of precipitated origin. Mapping of these environments is of great value in outlining field extensions and evaluation of acreage during development drilling. Use of these techniques, in addition to contruction of isopach maps of critical intervals, should also be highly effective in exploration for undiscovered reef oil and gas fields. End_of_Article - Last_Page 265------------

Pressure Maintenance Operations in the Sharon Ridge Canyon Unit, Scurry County, Tex.

Abstract The Sharon Ridge Canyon Unit is a pressure maintenance project using fresh surface water injected on a peripheral pattern. Canyon Reef limestone of Pennsylvanian age, occurring at approximately 6,700 ft, comprises the producing reservoir. The original producing mechanism was that of an undersaturated solution-gas drive. Rapid pressure decline and the threat of climbing gas-oil ratios pointed toward the need for pressure maintenance. Performance to date under the influence of water injection has been very encouraging. During six years of water injection, the volumetric average reservoir pressure has increased 338 psi, from 1,583 to 1,921 psi. The producing gas-oil ratio has been reduced from about 1,300 to about 900 cu ft/bbl. Before water injection, it was necessary to withdraw approximately 2.3 reservoir bbl in order to place 1 bbl of oil in the stock tank. Now, 1 bbl of stock-tank oil requires a withdrawal of only 1.8 reservoir bbl. Peripheral portions of the reservoir which have experienced encroachment by the injected water have performed better than predicted. Based on this history and recovery predictions, ultimate recovery as a result of this water injection will be at least 50 per cent of the original oil in place. This is twice the predicted recovery without pressure maintenance. Introduction With the completion of Humble Oil and Refining Co.'s R. E. Bishop 1 (now known as Tract 35, Well 1) in March, 1949, the Sharon Ridge Canyon field was discovered. This field is located approximately 20 miles southwest of Snyder, Tex., and its Pennsylvanian reef reservoir was divided from the Kelly Snyder and Diamond "M" fields by means of arbitrary lines. In Nov., 1951, the Sharon Ridge Canyon field was combined with the Diamond "M" field. Less than two years after the discovery well had been completed and with the field only 75 per cent developed, the operators met and formed the "Sharon Ridge Canyon Engineering Committee". A great amount of work and study directed toward a conservation program resulted in the formation of the Sharon Ridge Canyon Unit, with 100 per cent of the operators signing the agreement. On May 1, 1955, unitized operations commenced with a peripheral water-injection pressure maintenance program. JPT P. 645^

Pressure Maintenance in SACROC Unit Operations January 1, 1959

Abstract The SACROC Unit pressure maintenance plan does not depend on water injection alone for improving reservoir conditions, but in conjunction with 66 water injection wells located along the longitudinal axis of the Kelly-Snyder field, some 400 producing wells along the edge of the field have been shut in and their allowables transferred to more efficiently producing wells in the central portion of the field on either side of the line of injection wells. This supplemental history will generally follow the pattern of the previous paper, bringing reported operations tip to date and also presenting additional data pertinent to the stages of development occurring thus far in the life of SACROC Unit. Introduction It is one thing to discover an oil reservoir of 2,800 million STB, but quite another thing to produce it. The comparison between estimated recovery by pressure maintenance and ultimate recovery indicated by primary production resulted in the creation of SACROC Unit. The organizational setup of SACROC is most complex and little understood except by those intimately involved with overall operation, but no space will be taken to discuss that subject in this paper. Original Reservoir Conditions The Canyon Reef reservoir of the Kelly-Snyder field encompasses some 50,000 productive acres. The field was developed by approximately 82 operators with the wells drilled on 40-acre spacing. The Canyon Reef reservoir is encountered at an approximate depth of 6,700 ft, and varies from 0- to 795-ft thick. It is a low mound shape with gently dipping flanks. Average porosity of net reef is 10.03 per cent, and average porosity of gross is 7.11 per cent. Net pay is defined as reef having 3 per cent or greater porosity. The average permeability is 30.6 md to air. Initial oil saturation was 100 per cent of hydrocarbon pore space. Average interstitial water saturation was 28.2 per cent and the average reservoir temperature 130°F. The characteristics of the reservoir fluids are shown in Table 1.

Pilot Propane Project Completed in West Texas Reef

Abstract Injection of a 14,000-bbl "slug" of propane into a reef reservoir in an advanced stage of gas injection operations has resulted in miscible displacement of 100,000 bbl of stock-tank oil. Premature breakthrough of gas injected behind the slug is attributed to dilution of the propane slug, to unfavorable permeability distribution and to an insufficient amount of propane. Introduction The Millican field pilot propane project was intended to evaluate the applicability of the propane slug method to the Millican field (Fig. 1). A slug of 14,000 bbl of propane-butane mixture was injected in a single well followed by injected gas, and behavior of offset wells observed for two years. Recognized hazards were the high gas saturation due to the past history of gas injection and the non-uniformity of reef rock. Also, economic considerations limited the amount of propane which could be injected in a possible field-wide application. Favorable factors were a light oil containing a high proportion of intermediate hydrocarbons (see Table 1), gas injection facilities already in operation and a supply Of propane from a nearby gasoline plant. Despite the recognized hazards, project economics were considered favorable, since costs were low and any reduction in gas-oil ratio brought about by propane injection would be immediately reflected in increased oil production. History of Millican Field The Millican field, located in Coke County, Tex., produces from a Strawn reef limestone at 6,000 ft. Originally, the field had two small gas caps, and periodic material balance calculations indicate a closed reservoir. The oil was saturated at the original pressure of 2,540 psig at - 3,720 ft with 1,300 cu ft of gas per barrel and had a formation volume factor of 1.65. From core analyses, average porosity of the productive section of the reef is estimated at 6.6 per cent, connate water saturation at 20 per cent, and average permeability, 10 md. The field is completely unitized and produced gas has been returned since early in the history of the field.

Source of the Oil of the 'Tar Sands' of the Athabaska River, Alberta: ABSTRACT

The Tar Sands of the Athabaska River of Northern Alberta are believed to have derived their bituminous content from the underlying coral reef reservoirs of the Upper Devonian which come in contact, or near contact, with the sands at the unconformity between the Lower Cretaceous and the Upper Devonian. The sand was supplied from the pre-Cambrian Athabaska sandstone at the east on the Canadian Shield, and it is suggested that the escape of oil via fissures from the Devonian End_Page 2252------------------------------ reefs occurred primarily during and also after deposition of the Cretaceous sands. Diagrams illustrating possible conditions are presented. End_of_Article - Last_Page 2253------------

Developments in Canada in 1948

Developments in Canada in 1948