Wildcat Wells Research Articles

Are wildcat well outcomes dependent or independent?

A binary logit model is adapted to the spatial point process represented by outcomes of wildcat wells as a function of drilling history. The probability of success of the (n+1)st wildcat is made dependent on the well's location and on outcomes of wildcats previously drilled within a distanced of the well. This simple model is a device for investigating patterns of dependencies of wildcat well outcomes and for projecting probabilities of drilling success at particular locations. The model is applied to two Canadian petroleum plays.

Regional Variation in Microscopic and Megascopic Reservoir Heterogeneity in the Smackover Formation, Southwest Alabama

ABSTRACT Quantitative (rank) measures of microscopic and megascopic reservoir heterogeneity are used to characterize the distribution of reservoir heterogeneity in Smackover hydrocarbon fields and wildcat wells in southwest Alabama. Microscopic reservoir heterogeneity (µH) is {[(0.25) + (meanlnK) + (1.5lnK)]/3}. Megascopic Heterogeneity (MH) is [(# of reservoir intervals) + (# of high-K reservoir intervals) + ( of # of reservoir intervals)] where reservoir rock is defined as exhibiting permeability values >= 0.1 md and high-permeability reservoir rock exhibits permeability values >= 1.0 md. Both MH and µH are determined from core data. The Dykstra-Parsons coefficient (DP) is a measure of microscopic heterogeneity that is partially independent of µH(r2 = 0.428). All three of these parameters are primarily measures of vertical heterogeneity, although averaging of wells within a field incorporates lateral heterogeneity in µH and DP. µH and MH are distributed in contrasting but related patterns. µH generally decreases from northwest to southeast, with the highest values found in the vicinity of the Choctaw Ridge complex north of the Mississippi Interior Salt Basin (MISB). Moderately high values typify the Manila Embayment and the Conecuh Ridge complex to the south, whereas lower values are found in the MISB, on the north flank of the Wiggins Arch, and in the Conecuh Embayment. µH values are high in the Moldic Pore Facies and low in the Intercrystalline Pore Facies. The distribution of MH is roughly opposite to that of µH. MH values are high on the north flank of the Wiggins Arch, on the Conecuh Ridge complex and in the Conecuh Embayment: MH values are low near the Choctaw Ridge complex. The Conecuh Ridge is unique because it is characterized by high values of both µH and MH. Also, the low-relief north-south trending salt-cored anticline in western Washington County is characterized by relatively high values of MH. Reservoirs belonging to the Moldic Pore Facies tend to be homogeneous with respect to MH, whereas reservoirs assigned to the Intercrystalline Pore Facies are characterized by relatively high values of MH. MH and µH vary congruently with pore-system characteristics (controlled by depositional patterns, dissolution, and dolomitization) and regional structural and paleogeographic trends. This suggests that reservoir heterogeneity characteristics are controlled by structural and paleogeographic setting, by depositional fabric, and by diagenesis. However, because contours of µH and MH are approximately normal to structure contours but parallel to Smackover thickness contours, it appears that depositional setting (or paleogeography) influenced reservoir heterogeneity more than did structural evolution. The distribution of DP values is not related to pore-facies distribution. Thus we conclude that DP is less useful for regional heterogeneity studies than is MH or µH.

A petroleum discovery-rate forecast revisited—The problem of field growth

A forecast of the future rates of discovery of crude oil and natural gas for the 123,027-km2 Miocene/Pliocene trend in the Gulf of Mexico was made in 1980. This forecast was evaluated in 1988 by comparing two sets of data: (1) the actual versus the forecasted number of fields discovered, and (2) the actual versus the forecasted volumes of crude oil and natural gas discovered with the drilling of 1,820 wildcat wells along the trend between January 1, 1977, and December 31, 1985. The forecast specified that this level of drilling would result in the discovery of 217 fields containing 1.78 billion barrels of oil equivalent; however, 238 fields containing 3.57 billion barrels of oil equivalent were actually discovered. This underestimation is attributed to biases introduced by field growth and, to a lesser degree, the artificially low, pre-1970's price of natural gas that prevented many smaller gas fields from being brought into production at the time of their discovery; most of these fields contained less than 50 billion cubic feet of producible natural gas.

The Petroleum Province of Coastal Mississippi

The Wiggins Arch, a remnant structure associated with Late Triassic-Jurassic basement tectonics, separates the prolific Mesozoic-Cenozoic petroleum-bearing sediments of the Mississippi Interior Salt Basin from contemporaneous sediments south of the Wiggins Arch in the Mississippi Gulf Coast shelf. The coastal region of Mississippi has been an anomaly in an otherwise prolific oil and gas habitat of the Northern Gulf Coast Margin. Only sporadic and sparse exploration has taken place in the region, with limited success. Oil and gas exploration began in the coastal region of Mississippi in 1911 in southern Jackson County. The No. 1 Delamorton, Section 33, T7S-R5W, reached a depth of 3010 feet and tested the Oligocene/Miocene Heterostegina reef of the Catahoula Formation. The well tested salt water and was plugged. Sporadic exploration followed in the coastal area. The primary target during this early era of exploration was the relatively shallow Oligocene/Miocene Catahoula Formation and the underlying Oligocene Vicksburg group; however, no production was established. Exploration efforts then turned to structure-related t r a p s associated with the Hancock Ridge, a southwest spur of the Wiggins Arch. In 1955, Marshall R. Young Company drilled the Cuevas Heirs No. 1, Section 30, T9S-R15W, in southern Hancock County and established production in the Cuevas Sand of the basal Dantzler or the uppermost Washita-Fredericksburg Formation. The well was drilled on a structural high associated with the underlying Hancock Ridge. This was the first established production in the region. The Cuevas Heirs No. 1, the discovery well for Ansley Field, flowed 256 bbl. of 43 degree gravity oil per day and 1660 Mcf of gas per day from perforations from 10,841 to 10,852 feet. Development of the field resulted in production from pools in the Upper Tuscaloosa, Lower Tuscaloosa, and two separate Washita-Fredericksburg horizons. Continued exploration of the area resulted in the 1959 discovery of Kiln Field, Section 35, T7S-R15W, in southern Hancock County. Kiln Field is on the Hancock Ridge north of Ansley Field and also produces from the Cuevas Sand of the Washita-Fredericksburg Formation. In 1963, Humble Oil and Refining Company continued the exploration effort with a series of wells in southern Hancock County. In 1965, the Humble No. 1 Waveland Gas Unit, Section 22, T8S-R15W, established production from an argillaceous limestone in the Lower Cretaceous Mooringsport Formation. The well tested 30 bbl. of condensate per day and 1476 Mcf of gas per day through perforations from 13,484 to 13,490 feet. This was the discovery well for Waveland Field. Further development of the field has resulted in additional production from the Lower Cretaceous Paluxy and Washita-Fredericksburg and the Upper Jurassic Cotton Valley. The trapping mechanism at Waveland Field is a complex combination of structure and stratigraphy. A broad enlongated nose drapes across the Hancock Ridge at the Washita-Fredericksburg depth. Production is also influenced stratigraphically as the porous and permeable limestone grades up into an impermeable lime mudstone. A period of slower drilling activity in the region began in the early 1980's after the extensive development of Waveland Field. That lull in exploration activity continues today. Since 1982 only 18 wells have been drilled in the Mississippi Gulf Coast and the adjacent offshore tracts of the Mississippi Sound. Eight of those 18 were development wells in Waveland Field. Thus, only ten wildcat wells have been drilled in a roughly 4,600 square mile (12,000 km) area. There have been significant discoveries to the east of coastal Mississippi. Recent exploration in southwest Alabama and in its state and associated federal waters has resulted in the discovery of large gas reserves in the Jurassic Norphlet Formation. In February 1992, Chevron announced the discovery of 360 feet of Norphlet pay in Federal Block 861, Mobile Area. This block is adjacent to Mississippi-owned blocks south of Pascagoula, Mississippi. In the adjacent southwest block, Unocal tested its Norphlet discovery in Federal Block 904, Mobile Area. The well tested 97.6 MMcfd from 185 feet of pay. To date equivalent rocks in Mississippi waters have not been tested. Drilling in the Mississippi Sound and adjacent federal waters and more in-depth studies will be needed to determine the western limits of these prolific Norphlet dune fields. The discoveries of Jurassic Norphlet and Tertiary Miocene fields in southwest Alabama have generated numerous studies, some of which peripherally included the equivalent rocks in the Mississippi coastal area. Increased subsurface well data and advanced seismic and gravity data have provided new information, and the recent discoveries in southwest Alabama warrant a reexamination of the region. The large areal extent of the coastal region of Mississippi and the relatively sparse drilling of the area create a considerable opportunity for oil and gas exploration.

A Forecast of Undiscovered Oil and Gas in the Frio Strand Plain Trend: The Unfolding of a Very Large Exploration Play (1)

In this study, we examined the rate at which oil and gas fields were discovered in the Frio strand plain exploration play, which is located in the central coastal plain of Texas, and estimated the size distribution of the oil and gas fields remaining to be discovered. The analysis of past rates of discovery in this play provides insight into the advanced stages of an exploration play in which many very small fields have been discovered. This observation was made during examination of changes in the distribution of field sizes as the play was driven toward total physical exhaustion by the increased petroleum demand due to the massive rise in oil and gas prices in the late 1970s and early 1980s. During this period, exploratory drilling was directed at a suite of prospects t at contained very small oil and gas fields (almost all having less than 1 million bbl of recoverable oil equivalent). Analysis of this data suggests that the size distribution of fields is log geometric in form. On the basis of data obtained through February 1982, when 5000 wildcat wells had been drilled in the play, we predicted that 1163.2 fields remained to be discovered. Each field was estimated to contain more than 95,000 bbl of recoverable oil. The total volume of oil equivalent remaining to be discovered was predicted to be 726.8 million bbl, 51.5% of which is in fields smaller than 1.52 million bbl in size.

Controls on Porosity and Permeability Distribution in the Southern Cooper Basin, Australia: Implications for Petroleum Exploration

The Cooper basin, containing fluvio-lacustrine sediments of Permo-Triassic age, is one of Australia's major onshore hydrocarbon provinces, with sales gas reserves of about 6 tcf and gas-liquids and oil reserves of 310 MMSTB. It is characterized by dominantly low-porosity, low-permeability reservoir sandstones occurring at burial depths between about 1.8 to 3.6 km subsea. Average core porosity is 10.7% and permeability is 30 md. However, over 75% of sandstones have permeabilities less than 5 md. An early phase of silicification has mainly suppressed mechanical compaction in moderate to well-sorted sandstones of point bar origin. These reservoirs are prominent on major mid-flank structures and marginal areas of the basin. Toward the interior of the basin, microporosity associated with kaolin clays becomes predominant, accounting for the generally poor quality reservoir characteristics of most Cooper basin sandstones. Significantly, two the largest gas fields in the basin, Moomba and Big Lake, produce from reservoirs dominated by microporosity. Log-derived porosity estimates may overestimate effective porosity in sandstones containing kaolin minerals. Microporosity is likely to hold relatively large irreducible water, affecting hydrocarbon reserve calculations. The spatial distribution of core porosity and permeability is variable across the basin. The permeability relationship can be attributed to grain packing andmore » orientation, differential cementation, and sedimentary facies. However, sandstones of good reservoir quality still occur within low-permeability sequences, offering deep targets for petroleum exploration. The study used a variety of tools, including optical petrography, X-ray diffraction, scanning electron microscopy, and cathodoluminescence. The results were integrated with an excess of 6000 porosity and permeability values derived from 148 field and wildcat wells.« less

Integration of Multiple Oil and Gas Data Sources for Use in Forecasting Future Rates of Discovery of Oil and Gas

Discovery process models are commonly used to forecast both the amount of crude oil and natural gas remaining to be found and the rate at which they are going to be discovered in the future. These models require accurate estimates of the sizes of past discoveries and their interarrival times in the historical time series of wildcat wells drilled. The major source of well data is a commercial data base, the Petroleum Information Well History Control file, which consists of approximately two million records. Wells should be designated as successful or unsuccessful and as either discovery or development. Discovery wells far too often are not uniquely designated. In these situations, the discovery well has to be determined from other data. Several labor-intensive steps are required in order to convert the raw well and field information into data useful for forecasting. An additional problem is to determine the size of each field that has been discovered. Estimates of the ultimate productivity of fields are often contradictory, inaccurate, or in the case of many of the smaller fields, nonexistent. The correction of all these problems involves the examination of dictionaries such as the International Oil and Gas Scouts yearbooks. In the reconciliationmore » process, field codes, cumulative productions, formation names, depths, and numbers of well completions are used. The sizes of the final, conditioned data sets vary from one thousand to one hundred thousand wells and from one hundred to several thousand fields. At present, the method the authors have devised, which involves much statistical graphical analysis and hand labor, may be the only practical method for creating input data of acceptable quality for use in discovery process modeling.« less

Ordovician Carbonate Buildups: Potential Gas Reservoirs in the Ordos Basin, Central China

The Ordos basin of central China covers an area of about 25,000 km{sup 2}. A series of eastward moving overthrusts developed along its western flank, but most of the basin consists of a stable slope that dips westward less than one degree. The basin contains sediments from Sinian to Middle Ordovician and from the Middle Carboniferous to Cretaceous. Its evolutionary history is similar to that of the Alberta basin. Recently drilled wildcat wells have produced commercial gas flows that are closely associated with Ordovician carbonate buildups and a weathered surface between the Ordovician and Carboniferous. Most of the buildups consist of agal mounds; however, some Middle Ordovician reefs developed in the western portion and along the southern margin of the Ordos basin. More than 200 buildups were delineated using seismic stratigraphic techniques. They can be divided into four distinct types. The growth and distribution of buildups were controlled by sea-level fluctuations. The interpretations made in this study were based on the integration of results from a variety of analyses including vertical profiling, differential interformational velocity analysis, amplitude versus offset comparisons, G-log analysis, seismic modeling techniques, and high-precision gravity surveys. The best gas prospects are the Ordovician carbonate buildups distributed aroundmore » the basin's central uplift. The delineation of carbonate buildups and the demonstration that they are associated with commercial gas flows open the gate for future gas exploration in this area.« less

Let’s get rid of dumb exploration

It takes only a modest amount of imagination—or a dollop of paranoia—to conclude that a concerted effort is underway to get rid of petroleum exploration in the United States. All of the indicators of exploration activity support that conclusion (Figure 1). Since the historic peak of exploration activity in 1981, the number of new field wildcat wells drilled annually has dropped 68 percent, annual expenditure on new field wildcats has plummeted 77 percent, the average domestic rotary rig count fell by 76 percent, and the average number of geophysical crews working dwindled by 73 percent.

Haltenbanken hydrocarbon province (off-shore Mid-Norway)

Abstract Exploration drilling at Haltenbanken started in 1980 and to date 11 significant hydrocarbon discoveries have been made. The estimated total recoverable discovered reserves are 310 million SM3 of oil and condens and 305 billion SM3 of gas. Only 14 out of 25 proper wildcat wells turned out dry, giving a pure exploration success ratio of 44%. The major structural elements at Haltenbanken are (from East to West) the Troendelag Platform, the Halten Terrace and the Deep Moere Basin. The major hydrocarbon discoveries are located on the Halten Terrace and on the western margin of the Troendelas Platform. After a long period of regional passive subsidence during Triassic and most of Jurassic the Halten Terrace was formed as a consequence of Late Jurassic east-west rifting and early/middle Cretaceous north-south Dextral wrenching. During late Cretaceous and Tertiary again regional passive subsidence dominated. In Miocene very deep waters had developed at Haltenbanken as well as over most of the Mid-Norwegian Shelf. In Pliocene uplift of the Fennoscandian Shield resulted in rapid westward shelf progradation and deposition of up to 1000 m of sediments. This Pliocene burial had a great impact on the formation and entrapment of hydrocarbons at Haltenbanken. As the temperatures increased the rich Upper Jurassic marine and Lower Jurassic terrestrial source rocks passed through the oil window and are currently still producing large amounts of oil, condensates and gas. The rapid Pliocene sediment loading also led to great overpressure in the Upper Jurassic to palaeocene line-grained sequence. In the Eastern areas this overpressure resulted in a perfect seal over the Middle and Lower Jurassic sandstone reservoirs. In the Western areas also the Jurassic reservoir sequence is severely overpressured leading to less favourable sealing conditions. On the other hand, the overpressure in the reservoirs in the Western areas seems to have reduced the rate of compaction, hence preserving the porosity and permeability better at great depths. Seven of the most important discoveries at Haltenbanken are discussed as case examples. The variations in type of hydrocarbons (oil, vs. gas or gas/condensates) entrapped in the individual fields are caused by subtle, but important variations in source rock maturity, migration conditions (including drainage area and storeage capacity), trapping conditions (fill-spill or fill-leak), timing and PVT -conditions.

Oil and Gas Developments in Louisiana Gulf Coast Onshore in 1989

All three of the principal indicators of oil and gas activity fell significantly in onshore south Louisiana in 1989 after posting modest gains in 1988. Drilling activity in 1989 decreased 28% from the 1988 level of 696 wells to 500 wells. As in 1988, this drop was largely at the expense of development wells; a larger proportion of extension wells and a similar number of wildcat wells were drilled in each year. Operators drilled 56 new-field wildcats, 100 other exploratory wells, and 344 development wells. Overall success rate declined from 51% to 47% due to the decreased emphasis on development drilling. Six new-field discoveries were completed: 2 each in the Miocene and Eocene trends, and 1 each in the Oligocene and Cretaceous trends. There were 25 significant extension wells with 6, 14, 4, and 1 successful tests in Miocene, Oligocene, Eocene, and Cretaceous rocks, respectively. Land acquisition declined 20% relative to 1988 activity from 336,136 ac leased to 267,276 ac. The preferred leasing sites were Vermilion, Terrebonne, Calcasieu, St. Martin, East Feliciana, and Acadia Parishes. The Oligocene trend had the most leasing activity with more than 45% of industry activity, followed by the Miocene trend with 28%. Geophysical acquisition also dropped from 436.5 crew-weeks in 1988 to 327 crew-weeks in 1989, a decrease of 25%. Favored locales were Cameron, Vermilion, Calcasieu, Plaquemines, and Lafourche Parishes. Geophysical prospecting in the Miocene and Oligocene trends predominated, capturing 48% and 37% of industry interest, respectively.

Analysis of Subsidence and Modeling of Oil Formation in the Ragusa Basin (Iblean Plateau, Southeast Sicily): ABSTRACT

The Iblean plateau (southeastern Sicily) was part of the Apulian (African) margin of the Ligurian Tethys during the Mesozoic and played the role of a foreland during the Tertiary Alpine compression. From the Tortonian until the Holocene, the Apulian platform has been subducting northward underneath the European plate. Both the thickness and nature of the Apulian crust are poorly known. Subsurface data, from wildcat wells in the Ragusa petroleum basin, and backstripping have been used to quantify the vertical movements and thinning of the Apulian margin in southeastern Sicily. After quiet tectonics during the Middle Triassic, a rifting phase was initiated in the Hettangien, and lasted until the end of the Lias. Tectonic synrift subsidence can be great (up to 800 m in the wells analyzed). By contrast, the postrift subsidence, which gives an image of the lithospheric thermal anomaly, is very low. Comparison with some other current passive margin evolution, such as the Gulf of Lions, suggests that the Iblean plateau remained quite far away from the main axis of the rift. In this general tectonic context, the burial history of the source rocks, i,e., the Noto (Rhaetian) and Streppenosa (mainly Hettangien) formations are quite different from one areamore » of the Ragusa basin to another. Early Jurassic subsidence rates were relatively higher in the center and in the south, and this could have resulted in early oil kitchens in local grabens. On the contrary, in the north, oil formation is a very recent phenomenon, induced by the overthrust of the Maghrebidic (Apenninic) nappes.« less

Oil and Gas Developments in Alaska in 1989

A significant increase in exploration activity over past years occurred in 1989. Two and one-half times the number of exploration wells were drilled and evaluated, and more than twice as much geophysical work took place as in 1988. Included in this effort were the first 3 wildcat wells spudded in the frontier basin of the Chukchi Sea, and the announcement of a new oil field discovery at Point McIntyre on the Arctic Slope. The year's positive events were overshadowed significantly by the oil spill which occurred in March 1989 in Prince William Sound. The impacts of the spill are still being felt in oil and gas leasing, development, taxation, and petroleum transportation policies throughout the state of Alaska as well as nationwide. Despite this situation, the renew d exploration effort continued at the end of 1989, and promises to remain at least as strong through 1990.

Oil and Gas Developments in Upper Gulf Coast of Texas in 1989

Onshore drilling in the upper Gulf Coast of Texas during 1989 totaled 638 wells, a 21.6% decrease from 1988's total of 814 wells. Exploratory drilling remained at the same level, but development drilling declined 30.2% from 1988. Thirty-four new-field discoveries resulted from drilling 141 new-field wildcat wells in 1989, a 23.6% success rate. Fifty-three other wildcat discoveries resulted from drilling new-pool, deeper pool, or extension wells with a 60.2% success rate. The Eocene trend was once again the most active exploratory trend onshore with 40.6% of the onshore drilling; the Oligocene and Cretaceous trends had 25.3% and 3.1% of the onshore exploration activity, respectively. Offshore exploratory drilling in 1989 totaled 74 wells, a 32.1% decrease from 1988. Development drilling offshore nearly tripled with 174 development wells drilled in 1989 compared to 64 wells drilled in 1988. The exploratory success rate offshore was 31.1%. Exploration activity resulted in 20 new-field discoveries and 3 new-pool, deeper pool, or extension discoveries. Forty exploratory dry holes were drilled offshore in 1989. Offshore, the Miocene trend was most actively explored with 8.1% of the exploratory drilling in 1989 (66 wells were listed as undesignated).

Correlation and Implications of Results from Recent Wildcat Wells in Mid-Continent Rift in Northeastern Kansas: ABSTRACT

Three recent wildcat wells, the Texaco 1 Poersch (Sec. 31, T5S, R5E), the Producers Engineering et al 1 Finn (Sec. 4, T4S, R7E), and 1 Freiderich (Sec. 8, T7S, R5E), respectively, penetrated 8,455, 1,848, and 1,781 ft of Precambrian rocks in the Mid-Continent rift system (MRS) in Kansas. The Producers Engineering et al 1 Finn, which is 18 mi northeast of the Texaco 1 Poersch, encountered mostly arkosic sandstones and shales. The Producers Engineering et al 1 Freiderich, 7 mi south of the Texaco 1 Poersch, penetrated mafic igneous and volcanic clastic rocks. In contrast, the Poersch well drilled approximately 90% mafic igneous rocks and 10% arkosic sandstones in the upper 4,584 ft of the Precambrian section. In the lower 3,871 ft of the well, the proportions of these rock-types were reversed. No Precambrian petroleum source rocks were found in the Poersch and Freiderich wells, but 300 ft of gray siltstone (approximately 0.5% TOC) were encountered directly below the Precambrian unconformity in the Finn well. The Finn well also has significantly more red siltstones than the Poersch well, thereby possibly indicating more distal lacustrine or low-energy marine environments of deposition. Alluvial fans and playas are probably responsible for most of more » the sedimentary deposition in the Poersch well. Geophysical and well data indicate the MRS in northeastern Kansas is divided into small subbasins that probably are only a few tens of square miles in areal extent. Abrupt facies changes and complicated structure make lithostratigraphic correlations difficult. « less

Forecasting petroleum discoveries in sparsely drilled areas: Nigeria and the North Sea

Decline function methods for projecting future discoveries generally capture the crowding effects of wildcat wells on the discovery rate. However, these methods do not accommodate easily situations where exploration areas and horizons are expanding. In this paper, a method is presented that uses a mapping algorithm for separating these often countervailing influences. The method is applied to Nigeria and the North Sea. For an amount of future drilling equivalent to past drilling (825 wildcat wells), future discoveries (in resources found) for Nigeria are expected to decline by 68% per well but still amount to 8.5 billion barrels of oil equivalent (BOE). Similarly, for the total North Sea for an equivalent amount and mix among areas of past drilling (1322 wildcat wells), future discoveries are expected to amount to 17.9 billion BOE, whereas the average discovery rate per well is expected to decline by 71%.

Petroleum Geology of East-Central Tunisia

The tectonic features of Tunisia are complex and include folds, all types of faults, evaporite diapirs, and the Saharan flexure, which separates a stable Paleozoic province on the south from a subsidence zone of Mesozoic and Cenozoic strata of the offshore Ashtart and Tripolitania basins. The remainder of the offshore region is mostly stable shelf of the Pelagian craton, which also extends onshore. The present study focused on this shelf, where two carbonate intervals contain proven hydrocarbon reservoirs: the Metlaoui Formation of earliest Eocene (Ypresian) age and the Zebbag Formation of Late Cretaceous (Turonian) age. Regionally, well-defined belts of Metlaoui carbonates trend northwest. On the northeast are open-marine deep-water micrites and marls with abundant planktonic foraminifers. Thick bars of nummulitid packstone/grainstone were deposited in shallow water at an angle to the paleoshelf. The reservoir is confined largely to the bars, and visible effective porosity is best developed in those areas among the foraminifers filled with sand-size nummulitid debris, where secondary solution enlargement has occurred. This lithology tested oil in two recent wildcat wells and is a commercial reservoir at Sidi El Itayem and Ashtart fields. Distribution of Zebbag carbonates is more complex. A northwest-trending platform was bounded on three sides by deep water, where shale and micrite with planktonic foraminifers were deposited. Predominately back-reef and lagoonal foraminifer/rudist wackestones and packstones occur in narrow belts, apparently controlled at least locally by block faulting. They tested oil in two recent discoveries. The most significant porosity is interparticle, generally enlarged by solution, in foraminifer packstones, but intraparticle voids in foraminifers and rudists commonly contribute to the porosity. Analyses of surface and subsurface samples identified the Bahloul (basal Turonian) and Bou Dabbous (Ypresian) formations as source rocks. Fluorescence spectra of several oils were compared with extracts from these samples and indicate the Bahloul to be the source of oils in recent Metlaoui and Zebbag discoveries.

Oil and Gas Developments in Upper Gulf Coast of Texas in 1987

Onshore drilling in the upper Gulf Coast of Texas during 1987 totaled 822 wells, a 19.8% decrease from 1986's total of 1,025 wells. Exploratory drilling declined 17.5%, and development drilling decreased 20.5% from 1986. Twenty-two new-field discoveries resulted from drilling 123 new-field wildcat wells in 1987, for a 17.9% success rate. Forty-five other wildcat discoveries resulted from drilling new-pool, deeper pool, or extension wells, with a 64.3% success rate. The Eocene trend was the most active exploratory trend onshore with 38.9% of the onshore drilling; the Oligocene and Cretaceous trends had 27.4% and 26.4% of the onshore exploration activity, respectively. Offshore exploratory drilling in 1987 totaled 64 wells, an 18.5% increase from 1986. Development drilling offshore declined 51.0% with 50 development wells drilled in 1987 compared to 1986's total of 102 wells. The exploratory success rate offshore was 17.2%. Exploration activity resulted in 6 new-field discoveries and 5 new-pool, deeper pool, or extension discoveries. Fifty-three exploratory dry holes were drilled offshore in 1987. Offshore, the Miocene trend was most actively explored, receiving 59.4% of the exploratory drilling in 1987.

Role of the Engineer in the Petroleum E&P Industry in the Year 2000

Summary This paper examines the role of engineers in major oil companies during the period from 1986 to 2000. It looks at both the majors involvement in petroleum E&P and the significant technical challenges facing the industry for the remainder of the 20th century. The paper forecasts the functions of the engineer during this period, the computer support available to the engineer in the year 2000, and the qualifications required of the entry-level engineer in 2000. Introduction At the request of the SPE Education and Professionalism Committee, this paper addresses the five following questions.What aspects of the petroleum industry will major oil companies primarily be concerned with in the year 2000?What will be the significant technical problems addressed by the petroleum industry during the remainder of this century?What support will computers provide the engineer in the year 2000, and how should the engineer be prepared to use this technology effectively?How will the functions of engineers change during the remainder of this century?What will be the qualifications required for an entry-level engineering position in the petroleum industry in the year 2000? This paper does not and cannot predict the future price of oil, the estimated number of active drilling rigs, the job opportunities available for engineers in the petroleurn E&P industry, or any of the other standard measures of economic vitality. To do so would require an infallible econometric model, inerrant data about parameters going into the model, and above all, incredible prescience about future political developments worldwide. This paper is based on certain premises, however, which are summarized in Table 1. Major Oil Companies' Involvement in Petroleum E&P In the petroleum E&P or "upstream" business, major companies can be characterized as being more or less self-sustaining in their technical work. In exploration, their own employees do the geology and geophysics; in development and production, they do their own engineering and operations; in both, they are supported by their own research effort. Major oil companies are defined here as the top 16 oil companies, based on worldwide liquid reserves, of the 1984 OGJ 400.1 This grouping was used because of data accessibility. Thus major components of the worldwide petroleum E&P industry---e.g., British Petroleum, Royal Dutch/Shell Group, various national oil companies, and eastern European organizations---are not included in this analysis. Today major oil companies account for 4.7% of the world's liquid petroleum reserves, 4.3% of the gas reserves, and 16% of the liquids production (see Table 2). In the U.S., they drill about 15% of both the exploration wildcat wells and development wells, and probably do a somewhat larger percentage of the geologic and geophysical effort that supports this drilling. Whether these relative percentages will increase or decrease by the year 2000 is basically an economic/political question and beyond the scope of this paper. When considered on a global basis, the major oil companies will operate at a high-intensity level in the year 2000 in all four of the classic E&P functions: exploration, development, production, and EOR. In the U.S. only, the exploration and development functions probably will be at a moderate activity level because the U.S. will be well advanced in the so-called E&P cycle, with a smaller number of exploration and development opportunities available. These relative activity levels are summarized in Table 3. Significant Technical Challenges for the Remaining 20th Century To consider the technical challenges facing the petroleum industry during the remainder of this century, we return to the major E&P functions of development, production, etc. Development. Table 4 summarizes the future problems and challenges of the development function. The two major challenges in developing oil and gas reserves will be an early, accurate characterization of the reservoir and optimal engineering design in drilling and completing the wells. Development. Table 4 summarizes the future problems and challenges of the development function. The two major challenges in developing oil and gas reserves will be an early, accurate characterization of the reservoir and optimal engineering design in drilling and completing the wells.

Application of Tidal Mudflat Model to Sunniland Formation (Lower Cretaceous) of South Florida: ABSTRACT

For many years, the Lower Cretaceous Sunniland oil-producing fields have been interpreted as reef deposits. Petrologic evidence from cores from field and wildcat wells strongly indicates on the basis of faunal composition and character, that the fields are producing from moundlike shoals. These shoals are considered to have been deposited in a mudflat environment similar to that of present-day Florida Bay. This present-day Florida Bay analog is used to determine the various environmental subzones and controls on the deposition of the Sunniland Formation. This concept of using a model together with a modern analog can be a powerful tool in the exploration of stratigraphic traps. A petrologic and petrophysical study of the Sunniland Formation in the wells that have been drilled in the Florida Bay and Keys areas was made to extend the model and its application throughout the South Florida basin. The evaluation of these wells has produced new insights into the tectonics of this basin and its relationship to the Bahamas and Caribbean areas.