MCF Of Gas Research Articles

Case Study: Patent-Pending Rigless Chemical Process Enhances Oil and Gas Production in Eagle Ford

Hydrocarbon production losses resulting from parent-child well interactions during completion operations are a significant challenge in the Eagle Ford. A patent-pending rigless chemical frac hit remediation process was implemented in the Eagle Ford formation resulting in a 60% increase in oil production, a 30% increase in BOE reserves, and a payback in less than 4 months. A thorough engineering and lab study was conducted to design the process which addressed the damage mechanisms of capillary phase trapping, reduced hydrocarbon relative permeability, paraffin deposition, and minor scale deposition. Background and Challenge The Eagle Ford Shale play located across South Texas is a prolific unconventional resource producing approximately 967,000 BOPD and 6 Bcf/D of natural gas through 2021 (US Energy Information Administration). Like other unconventional reservoirs, Eagle Ford wells have high initial production rates but decline rapidly. Later-life production rates can significantly influence well economics and base production profitability. Production in the Eagle Ford rapidly started increasing around 2010 with the implementation of horizontal drilling and hydraulic fracturing. However, as operators started to develop their acreage, they quickly turned to drilling of infill wells, also known as child wells. Lindsay et al. (SPE 189875) reported that by the beginning of 2015, the number of child wells being drilled in the Eagle Ford surpassed the number of existing or parent wells. This resulted in an acceleration of child-parent interactions, defined as interwell communication between the child and the parent during the fracturing of the child well. Known as fracture-driven interference or frac hits, these interactions have been of intense interest in the industry due to the potential degradation of production in both the parent and child well. Miller et al. (SPE 180200) reported that in 1,210 instances studied in the Eagle Ford, the parent well experienced a negative production event approximately 41% of the time. Kairos Energy Services conducted a study on Eagle Ford parent wells that experienced negative production events from a frac hit to quantify the change in production. A total of six wells were analyzed where each had modern completions and were brought onto production in 2019 or later. Decline curve analysis was run on both the oil and gas streams before the frac hit to generate a forecast to compare against actual post-frac-hit production. Actual and forecast production was averaged across the six wells and production responses were analyzed 6 months before and after the frac hit. Fig. 1 shows the forecast vs. actual cumulative production for both oil and gas, respectively. The divergence in production post frac hit can be clearly seen, resulting in an average per well loss of 20,500 bbl of oil and 245,000 Mcf of gas 6 months following the frac hit. All wells showed a significant increase in water production directly after the frac hit, indicating hydraulic communication. The gas/oil ratio (GOR) was significantly suppressed, decreasing from 4,820 ft3/bbl to 3,850 ft3/bbl 6 months post frac hit. The 30-day average water cut also showed a sustained change, increasing from 46% to 63% 6 months post frac hit.

Mexican Unconventional Plays: Geoscience, Endowment, and Economic Considerations

Summary Successful activities in the Eagle Ford Shale in Texas through drilling of horizontal wells and completions by use of multistage-hydraulic-fracturing jobs suggest that the potential of shale reservoirs farther south will be quite significant. This observation leads to the objective of this paper: to examine geoscience and engineering data of tight and shale reservoirs in Mexico with a view to estimating the oil and gas endowment, and to determine the economics of developing these plays under current and forecast possible oil and gas prices. Plays considered in this study include the Burgos, Sabinas, Tampico, Tuxpan (Platform), Veracruz, and Chihuahua Basins. Endowment is defined by the US Geological Survey (USGS) (USGS 2000) as the sum of known volumes of oil and gas (cumulative production plus remaining reserves) and undiscovered volumes. The economics of these plays is examined with the use of cumulative long-run supply (or availability) curves. These are presented as crossplots of production costs per barrel of oil or per Mcf of gas vs. endowments for the aggregate of basins, and are very useful to demonstrate how endowment volumes vary at different price levels. It is concluded that the potential of unconventional resources in Mexico is quite significant and will help to change the slope of production rates in the country from negative to positive. As a result, it is anticipated that Mexico will become an important part of the shale-petroleum revolution started in the US.

Taylor Canyon Field and Government Pool of Morales Canyon Oil Field, San Luis Obispo County, California: ABSTRACT

The Taylor Canyon field and the Government pool of the Morales Canyon oil field represent two northernmost producing fields of the Cuyama basin. The Government pool was discovered by Superior Oil Company in April 1950. The discovery well was the Government 18-2. The Taylor Canyon field was discovered in August 1950 by Hancock Oil Company. The discovery well was the Hancock-Bishop 44-1. Cumulative production in the Taylor Canyon Field is 486,000 bbl of oil and 141,000 mcf of gas from two wells. The field is now abandoned. Cumulative production in the government pool through December 1986, was 1,383,000 bbl of oil and 1,272,000 mcf of gas from seven wells. One well was producing at the end of 1986. The geology of both fields is extremely complicated both stratigraphically and structurally. The Taylor Canyon field produces from basal Miocene (Soda Lake) sands and conglomerates and possibly an older sand, referred to as the Turritella variata sand. The Government pool produces from the basal Miocene and Turritella variata sands and fractured granitic rocks. It is possible one or two wells in the Government pool may be producing from the Dibblee sand. Both fields produce beneath the White Rock thrust. The basal Miocenemore » sands are definitely older than the producing Colgrove sand of the nearby Russell Ranch oil field. The trapping mechanism in both fields appears to be permeability variations and faulting on a gently bowing east-plunging nose. The producing zones lie on Cretaceous strata in the Taylor Canyon field and both Cretaceous and granitic basement in the Government pool.« less

Houston Lighting and Power Company Evaluation of Compressed Air Energy Storage

Compressed air energy storage (CAES) is a resource being evaluated by Houston Lighting and Power Company (HL&P). There is underground salt formation suitable for CAES development around HL&P's service area. This paper presents the results of a preliminary economic analysis of a 660 MW CAES plant in 1994 in comparison with a coal/lignite plant. Sensitivity analysis was conducted to examine the effect of off-peak charging energy from outside systems and the effect of gas prices. Results indicated that the CAES plant had a benefit to cost ratio of 1.15 which would be raised above 1.5 if off-system charging energy at a reasonable price could be obtained. Decreasing gas price would favor CAES in comparison with coal or lignite. The CAES plant in operation would save 5 to 13 million mcf of gas per year.

A Community Model for Coalbed Methane Utilization: ABSTRACT

The University of Alabama at Tuscaloosa provides a model for community utilization of coalbed methane and energy independence. A feasibility study for coalbed methane development has been completed through a grant from the U. S. Department of Energy. The total resource available beneath the 760-acre (310-ha.) campus is estimated to be nearly 10 bcf. The Mary Lee Coal Group alone contains more than 3.4 mcf of gas, assuming 75% recovery. As a result of an economic analysis, two exploration/research wells have been completed to depths of 2,289 and 2,760 ft (698 and 841 m) respectively. The university is currently in the process of unitizing with Bryce and Partlow Hospitals. The combined acreage is approximately 2,000 acres (800 ha.). It is anticipated that coalbed methane could meet the gas demands of all three facilities for many decades. The methane will be used for space heating, domestic hot water, and for compressed natural gas (CNG) to operate the university's vehicle fleet. Recently the university, along with Southern Company Services, Kaneb Services, and the Gas Research Institute, has embarked on a demonstration project to evaluate the feasibility of using coalbed methane as a primary fuel source for a fuel-cell power plant. A 40-kW fuel cell will be utilized to provide both electricity and hot water for the student recreation building. These coalbed methane utilization activities should provide planning information for communities located over coal lands to develop independent resources and provide long term energy alternatives. End_of_Article - Last_Page 457------------

Geology of Abo Gas-Producing Areas of Pecos Slope, Chaves County, New Mexico: ABSTRACT

The discovery of Abo gas production from continental Permian red beds in north-central Chaves County, New Mexico, resulted in a flurry of drilling activity. Yates Petroleum Corp. reentered the Honolulu 1 McConkey, an Ellenburger dry hole, and completed it from Abo perforations for an initial potential of 2,551 mcf of gas per day and 1 bbl of condensate per day. Although this discovery was completed in September 1977, drilling continued at a slow pace until federal regulations designated the Abo formation as tight gas sands, in 1980. This stimulated drilling activity to the extent that, as of August 1983, almost 850 wells had been drilled, with a high success ratio. Lee named the Abo formation for sandstone exposures in Abo Canyon, at the south end of the Manzano Mountains, southeast of Albuquerque. Needham and Bates re-described the Abo and named a type section for exposures in Socorro and Torrance Counties and considered it to be of continental origin because of cross-bedding, plant remains, and other characteristics. The Abo is generally believed to be Wolfcampian in age; however, in a few areas the upper portion of the Abo is Leonardian. This is based partly on fossils and also on the fact that the Abo in places grades into the overlying Yeso. The Pedernal landmass, situated to the north and west of the Pecos slope area, provided most of the sediments as siltstones, sandstones, mudstones, and shales. The sandstones are characteristically arkosic in most areas. These Abo sediments were deposited under fluvial-deltaic conditions. End_of_Article - Last_Page 119------------

Oil and Gas Developments in Four Corners--Intermountain Area in 1981

Exploratory drilling in the Four Corners-Intermountain area increased sharply in 1981, with 335 wells drilled. Drilling activity was up in all states. A total of 129 successful wells was completed, yielding a success rate of 38.5%, up from 28% in 1980. Total exploratory footage drilled was up nearly 79.5% from 1980, with 1,980,462 ft drilled in all exploratory categories. Development drilling increased 28.2% from 1980 with 1,414 holes drilled, most of which were in the San Juan basin, as in previous years. The region's most significant discovery was in the Overthrust belt of northern Utah, where the confirmation test of the Anschutz Ranch East field was completed by Anschutz. The 8-20u Anschutz Ranch East (Sec. 20, T4N, R8E) flowed 7,268 mcf of gas and 1,488 bbl of condensate from Nugget (13,050 to 13,574 ft). In southeastern Utah, the Superior 27-32 Sentinel Peak (Sec. 27, T41S, R26E) flowed 552 BOPD and 423 MCFGD from the Middle Pennsylvanian Ismay (Paradox). In Nevada, Northwest Exploration opened the Bacon Flat field with the discovery well pumping 222 BOPD and 619 BWPD from Paleozoic rocks at 5,316 to 5,354 ft. Exploratory drilling remains high in the region with the Overthrust belt and Cordilleran hinge-line area attracting most of the attention. However, increased activity in Utah's Uinta and Paradox basins accounts for the bulk of the state's drilling.

Oil and Gas Developments in Michigan in 1981

The exploration for and development of Middle Silurian Niagaran reefs dominated Michigan's oil and gas industry activity for the 13th year in a row. Heaviest drilling was concentrated in the northern part of the Southern Peninsula along the reef trend. Reef exploration also continued at a high pace in south-central and southeastern Michigan. Overall, well completions in 1981 broke a 20-year record. Exploration resulted in 69 new discoveries, 84% of which were new Niagaran reef reservoirs. A gas discovery in the Prairie du Chien Group, at a depth greater than 10,000 ft, generated a great deal of excitement in the central basin deep play. Exploration and development footage figures, derived from Michigan Geological Survey Division records, amounted to 1,766,593 ft exploratory and 1,255,759 ft development compared with 1,375,993 ft exploratory and 1,468,038 ft development drilled in 1980. An additional 135,686 ft, mainly gas storage facility wells, is credited to 1981. Oil and gas production declined slightly in 1981. Preliminary figures show that Michigan produced 32,664,000 bbl of oil (including condensate) and 152,593 mcf of gas. Niagaran reef reservoirs located along the northern reef trend accounted for approximately 72% of the oil and 83% of the gas produced in 1981.

Hoadley--A Potential Supergiant Gas Field in South-Central Alberta, Canada: ABSTRACT

The Hoadley gas field is a potential supergiant gas condensate accumulation, discovered in November 1977 by Sundance Oil. The discovery well, Sundance et al Hoadley 6-2, has an AOF of 26 mmcf of gas per day with 60 bbl of natural gas liquids per mcf of gas. The field covers approximately 1,500 mi2 (3,885 km2) in south-central Alberta. The producing zone is in the Lower Cretaceous Glauconitic formation consisting of 25 to 80 ft (7.6 to 14.4 m) of sandstone pay. The sand was deposited as a gigantic marine barrier bar with an approximate width of 15 mi (24 km) and a length of more than 130 mi (209 km), trending southwest-northeast across south-central Alberta. The central and southwestern part of the barrier bar (approximately 100 mi [161 km] long) is e tirely saturated with gas and natural gas liquids. Of more than 100 Glauconitic gas wells completed within this section of the barrier bar since discovery, none has tested or produced salt water. The field is estimated to contain a potential recoverable reserve of 6 to 7 tcf of gas, and a potential recoverable reserve of 350 to 400 million bbl of natural gas liquids. End_Page 961------------------------------ The geology of the Hoadley gas field is a classic example of a modern barrier-bar complex. Principal facies recognized in the studied area include marine shale, bay, barrier sand bar, eolian sand ridge, tidal channel, levee, inter-bar lagoon, and back-bar washed sands. A deltaic complex, found immediately to the southeast of the barrier bar, includes deltaic distributary channel and abandoned channel sand facies. Each of these facies can be recognized from diagnostic electric-log characteristics. End_of_Article - Last_Page 962------------

Developments in Michigan in 1979

Niagaran reef exploration dominated drilling activity for the 11th straight year. Exploration and development drilling for these Middle Silurian reef reservoirs were heaviest in northern counties along the reef trend. Other pockets of high activity were associated with deeper development drilling in older fields in the central basin, in parts of southeastern Michigan, and in the Ingham-Calhoun-Eaton County region of southern Michigan. Exploration resulted in 70 new discoveries, one of which resulted from reworking of an earlier dry hole drilled in 1960. Of the new discoveries credited to 1979, 55 were new Niagaran reef reservoirs, 39 of which were located along various parts of the northern reef trend. Two new reef reservoirs in the Livingston-Oakland County region indicate additional prospects in this area of the basin. Exploration and development footage figures, derived from Department of Natural Resources, Geological Survey Division records, amounted to 1,146,515 ft exploratory and 1,150,710 ft development compared with 1,128,691 ft exploratory and 1,176,270 ft development drilled in 1978. An additional 202,791 ft, mainly gas-storage facility wells, is credited to 1979. Oil and gas production continued to set new records. Preliminary figures show that 35,428,411 bbl of oil (including condensate) and 161,707,877 Mcf of gas were produced in 1979. Both figures are new records for annual production. Niagaran reef reservoirs distributed along the northern reef trend accounted for about 72% of the oil and 84% of the gas produced in 1979.

Promising Morrow Sandstone Discoveries in Southeastern Colorado: ABSTRACT

Eight new Morrow oil and gas fields have been discovered in southeastern Colorado during the past two years. The latest discovery resulted in a well flowing oil from a Morrow sandstone at an initial rate of 700 bbl of oil per day and 750 Mcf of gas per day. The trapping mechanism in this well, as in most, is a stratigraphic and structural combination. The depositional history of Morrow sandstones in southeastern Colorado was strongly influenced by regional tilt into the Anadarko basin, established at the close of Mississippian time. Mississippian rocks were subject to truncation in the area of the Las Animas arch and development of karst topography on the erosion surface. Transgression of the sea from the southeast in Morrowan time resulted in the deposition of a sandstone and shale sequence. The Morrow series consists of a basal transgressive sandstone member (Keyes sandstone) overlain by at least three sandstone units deposited during regressive pulses in an overall transgressive sequence. These Morrow sandstones generally trend from northwest to southeast toward the Anadarko basin; their source is inferred to have been the ancestral Rocky Mountain End_Page 672------------------------------ uplift for the upper sequence and the Amarillo uplift for the basal Keyes member. The environment of deposition appears to have been fluvial delta plains and associated tidal channels which were alternately created and destroyed by regression and transgression of the Morrowan seas. Distribution of these elongate sandstones is generally erratic and meandering; individual sand bodies have an estimated width of up to 1 mi (1.6 km) and a maximum thickness of 42 ft (12.8 m). The nature and distribution of these sandstones leave many areas essentially unexplored. Southeastern Colorado has had substantial Morrow discoveries which justify a closer look at the area. End_of_Article - Last_Page 673------------

Developments in Michigan in 1978

Niagaran reef exploration dominated drilling activity for the 10th straight year. Exploration and development drilling were heaviest in northern counties along the reef trend. Other pockets of concentrated activity were associated with deeper development drilling in older fields in the central basin, in southeastern Michigan, and in the Ingham-Calhoun-Eaton County region of southern Michigan. Exploration resulted in 52 new discoveries, nearly all of which were Salina-Niagaran reef reservoirs; 39 of the reef reservoirs were along parts of the northern reef trend. A definite pinnacle reef in Livingston County, southern Michigan, indicates additional prospects in this area. Exploratory and development footage, figures from records of the Department of Natural Resources Geological Survey Division, amounted to 1,128,691 ft exploratory and 1,176,270 ft development, compared with a combined total of 2,519,809 ft in 1977. An additional 225,420 ft, mainly gas-storage facility wells, is credited to 1978. Oil and gas production continued to set new records as additional reef reservoirs are found. Preliminary figures show that 34,667,312 bbl of oil (including condensate) and 150,535,238 Mcf of gas were produced in 1978. Both figures are new records for annual production and are direct results of Silurian Salina-Niagaran reef developments.

Developments in Michigan in 1977

Niagaran reef exploration continued to dominate drilling activity for the ninth straight year. Exploration was heaviest in northern counties along the reef trend. Other pockets of activity were apparent in southeastern Michigan and in the Ingham-Calhoun-Eaton County region. Exploration in these parts of the basin was mainly for Niagaran reefs. Exploration resulted in 71 new discoveries, nearly all of which were Salina-Niagaran reef reservoirs. About 80% of the new discoveries were directly associated with the northern reef trend. Four new reefs in Presque Isle County indicate future developments in the coming year. Exploratory and development footage, figured from records of the Michigan Department of Natural Resources Geological Survey Division, amounted to 2,519,809 compared with 2,349,191 drilled in 1976. An additional 89,637 ft, mainly gas storage facility wells, is credited to 1977. Oil and gas production continues to set new records as additional reef reservoirs are found. Preliminary figures show that 32,964,503 bbl of oil (including condensate) and 133,215,209 Mcf of gas were produced in 1977. Both figures are new records and are direct results of Silurian Salina-Niagaran reef developments.

Developments in Michigan in 1976

Niagaran reef exploration continued to dominate drilling activity for the eighth straight year. Exploration was heaviest in northern counties along the reef trend. Pockets of activity were apparent in the Ingham-Calhoun-Eaton County region and in southeastern Michigan in a resurgence of reef exploration. Exploration resulted in 62 new discoveries. Nearly all are Salina-Niagaran reef reservoirs, about 81% of them credited to the Western and Northern districts. Oil and gas production was established for the first time in Benzie and Cheboygan Counties by the discovery of Niagaran reef reservoirs. New discoveries in Presque Isle County now extend the reef trend virtually to the shores of Lake Huron. Exploratory and development footage, figured from Department of Natural Resources, Geology Division, records amounted to 2,349,191 compared with 2,519,672 drilled in 1975. An additional 94,714 ft, mainly gas storage facility wells, is credited to 1976. Oil and gas production continues to set new records as additional reef reservoirs are found. Preliminary figures show that 30,421,533 bbl of oil (including condensate) and 120,252,528 Mcf of gas were produced in 1976. Both figures are new records and are direct results of Silurian Salina-Niagaran reef developments.

Developments in Eastern Canada in 1975

The production of natural gas in Eastern Canada increased sharply in 1975 but oil production decreased slightly. A total of 11,070,000 Mcf of gas and 707,166 bbl of oil was produced. This represents a production increase of 46.8% in gas and a decrease of 4% in oil from 1974. In Eastern Canada, geophysical activity and exploratory drilling declined as compared with the previous year. Some acreage was surrendered in the offshore areas of Hudson Bay, the Atlantic, and the Labrador Sea. Even though Quebec and Prince Edward Island experienced lease-acreage increases, other remaining land areas decreased, especially the Hudson Bay lowlands where approximately 98% of the acreage was dropped. Nine dry exploratory tests were completed on land areas, and 12 wells were drilled offshore. Three of these offshore wells were suspended and may be deepened during the coming summer. Hydrocarbons were encountered in 2 of the wells. In southwestern Ontario, 66 exploratory and 71 development wells were drilled in 1975, a decrease of 14 exploratory and an increase of 11 development wells over 1974. Silurian development drilling increased 59% offshore and 11% in the exploratory class. However, development drilling for other objectives experienced 9% decrease and a 30% drop in the exploratory category. Two Silurian reef structures (1 oil, 1 gas) in Lambton County and a Cambrian new-pool wildcat discovery in Dunwich Township, Elgin County, were the most significant discoveries in 1975. Several significant gas discoveries were made last year in Lake Erie together with a notable development drilling program.

Developments in Eastern Canada, 1973

The production of natural gas and petroleum in eastern Canada declined sharply in 1973. A total of 9,727,300 Mcf of gas and 816,323 bbl of oil was produced. This represents a decrease of 23% gas and 8% oil from 1972. In the Hudson Platform region, exploratory drilling was limited to a single 1,729-ft exploratory test on the south margin of the Moose River basin. In southwestern Ontario, 51 exploratory tests and 56 development wells were drilled during 1973, a decrease of 33 exploratory and an increase of 9 development wells from 1972. Silurian exploratory drilling, both onshore and in Lake Erie, underwent a moderate decline, but Silurian development drilling increased slightly. The overall drop in exploratory drilling is reflected in a 25% decrease in total footage drilled. Four of the 5 gas discoveries were made in Lake Erie. A gas-bearing Silurian patch reef, discovered off Kent County in Lake Erie, and a Cambrian oil discovery in Ekfrid Township were the most significant discoveries in southwestern Ontario in 1973. In Quebec 3 dry exploratory tests were drilled, and 5 crew-months of geophysical work were completed. In the Atlantic Provinces, 3 dry exploratory tests were drilled onshore, in New Brunswick, Nova Scotia, and Newfoundland. Offshore drilling was increasingly active, with 29 completions, 12 more than last year. Four of these were extensions to the Sable Island oil and gas discovery of 1971. Of the 25 wildcat wells, 2 found encouraging shows of hydrocarbons, and one, considered an oil discovery, is presently suspended. A total of 29.5 crew-months of geophysical work was completed in the offshore region. The area under permit for oil and gas exploration in the offshore is virtually unchanged from the previous year.

Possible Ordovician Carbonate Reservoirs in Mississippi: GEOLOGIC NOTES

To mid-1973, carbonate rocks of Ordovician age in north Mississippi had produced 7,813 bbl of 35° gravity oil from one well and 123,752 MCF of gas from another. In spite of the poor results of exploration of Ordovician strata, large reservoirs may be present in these oil- and gas-bearing limestones and dolomites, and structural and stratigraphic conditions may favor commercially profitable accumulations of oil and gas. Porosity is found in fractured and vuggy dolomite, in sucrosic dolomite, in secondarily dolomitized limestone, in coquinoid or reef limestone, in oolitic limestone, and in chert residuum from post-Ordovician, Early Silurian, lixiviation.

Developments in Eastern Canada, 1972

The production of both natural gas and petroleum in eastern Canada declined during 1972. A total of 12,691,588 Mcf of gas and 886,618 bbl of oil was produced. This represents a decrease of 3,476,143 Mcf (22%) of gas and a decrease of 80,104 bbl (8%) of oil from the previous year. In the Moose River basin of the Hudson platform region, industry drilled 4 exploratory tests, totaling 3,779 ft. In southwestern Ontario 84 exploratory tests and 47 development wells were completed during the year, an increase of 21 exploratory and a decrease of 19 development wells from 1971. Silurian exploratory drilling both onshore and in Lake Erie indicated a substantial increase, but Silurian development drilling continued to decline. A moderate drop in Cambrian drilling resulted in a 13% decrease in total footage. Of the 8 Silurian gas discoveries, 6 were in Lake Erie. An oil-filled Silurian pinnacle reef discovered near Petrolia rated as the most significant discovery in southwestern Ontario in 1972. In Quebec, 6 dry exploratory tests were drilled. Industry completed 16.5 crew-months of geophysical work, practically all seismic. In the Atlantic provinces, 2 dry exploratory tests were drilled onshore on Prince Edward Island. The offshore pace remained steady with 17 holes drilled, 3 of which were extensions to the Sable Island discovery reported last year. These 3 found undisclosed amounts of hydrocarbons. Four of the remaining 14 holes tested gas or oil. Offshore holdings dropped slightly from 476,454,433 acres in 1971 to 402,769,437 acres at the close of 1972. Industry accounted for 62 crew-months of geophysical activity offshore.

Discovery and Development of Sawtelle Oil Field: ABSTRACT

The Sawtelle oil field, discovered by Occidental Petroleum Corporation in 1965, is the westernmost of nine producing fields along a 15-mi trend of anticlinal oil accumulations distributed en echelon along the northerly margin of the Los Angeles basin. Wells at Sawtelle confirm that the normal stratigraphic section has been disordered by approximately 7,000 ft of apparent vertical displacement along the northerly trending Santa Monica thrust fault zone. The mountainous hanging wall block is comprised of a thin veneer of recent sediments; nonproductive lower Pliocene and upper Miocene sandstone and shale; middle Miocene sandstone, shale, and volcanic rocks; and Mesozoic Santa Monica Slate. Beneath the fault zone, within the basinal footwall block, are lower Pliocene sandstones and shales, oil-bearing upper Miocene sandstone and shales, and middle Miocene sandstones and shales. Production has been established in two pools: on the south in the upper Miocene Rancho sands within an asymmetric southeast-trending anticline where net pay exceeds 500 ft, and on the north where these same sands appear even thicker within the south limb remnant of a parallel anticline which has been End_Page 432------------------------------ dragged upward and overturned along the hanging wall block of the Santa Monica fault zone. Thirteen wells have been completed beneath the Federal lands of the Sawtelle Veterans Hospital and an adjacent town-lot area on the north. Production through 1971 totals 6,470,000 bbl of oil and 5,790 MMcf of gas. Current production is 2,000 bbl of oil per day and 2,600 Mcf of gas per day. Average vertical depth to the top of the zone is 9,500 ft; initial pressures were hydrostatic. Porosity averages 18% and permeability averages 20 md. Connate water averages 27%; and oil gravity ranges from 18 to 26° API. Minor exploration potential remains, but drilling costs are considered too high to justify additional work, and development is therefore considered complete. End_of_Article - Last_Page 433------------

Supplemental Recovery Development of The Intisar "A" and "D" Reef Fields, Libyan Arab Republic

Large-scale pressure maintenance programs were begun very early in the producing life of these giant fields to maximize oil recovery and conserve producing life of these giant fields to maximize oil recovery and conserve associated gas. It is estimated that a continuation of these programs will effect a combined recovery of more than 60 percent of the oil originally in place and will conserve nearly 2 trillion cubic feet of natural gas for future use. Introduction Supplemental recovery operations were begun early in the Intisar "A" and "D" Reef reservoirs to maximize ultimate oil recovery, maintain flowing production. and conserve natural gas and gas liquids. production. and conserve natural gas and gas liquids. These giant fields originally contained approximately 4 billion bbl of stock-tank oil. Because the oil in both reservoirs was highly undersaturated, primary recovery efficiency was indicated to be relatively low, necessitating the installation of large water- and gas-injection pressure maintenance programs very early in their productive lives. This paper reviews the reservoir engineering planning and development work that led to the planning and development work that led to the installation of a 500,000 B/D bottom-water injection program in the Intisar "A" field and a combination program in the Intisar "A" field and a combination miscible gas-water displacement program in the Intisar "D" field. The projected peak injection rates in the latter were 700,000 Mcf of gas per day and 400,000 BWPD. A large gas liquids extraction plant, completed early in 1972, also was constructed as an integral part of this gas reinjection project. Water injection was begun in the Intisar "A" field less than 6 months after the held was placed on production. In the Intisar "D" reservoir, water production. In the Intisar "D" reservoir, water injection was started almost coincidentally with production, and crestal gas injection operations were production, and crestal gas injection operations were begun less than 15 months later. These pressure maintenance programs were completely implemented in July, 1971 when the last of three huge gas compressors was commissioned. Thus, the primary and supplemental development of these two fields was completed barely 4 years after the discovery of the first reservoir in April, 1967. This supplemental development was accomplished quickly in order to optimize ultimate oil recovery. It is estimated that these timely pressure maintenance programs will ultimately result in the recovery of approximately three times as much oil from the two fields as would have been realized by primary means alone. In addition, almost 2 Tcf of associated natural gas will be conserved for future use. Discovery and Development The Intisar "A", "C", and "D" field complex is located in the cast-central part of the Libyan Arab Republic's petroleum-rich Sirte Basin. The Intisar "A" and "D" fields are only 15 miles apart and lie within Occidental of Libya's 465,000-acre Concession 103, located about 220 miles due south of Benghazi and 525 miles cast-southeast of Tripoli (see Fig. 1). This concession was awarded in March, 1966, and seismic operations were begun there early in 1967. In April, 1967, the first well drilled on the concession, A1-103, discovered a major oil accumulation when it penetrated oil-bearing Paleocene carbonate rock at a well depth of 9,417 ft. JPT P. 785