The southern San Joaquin basin is a prolific oil-producing area that has had a complex tectonic and depositional history. It originated as the southern part of a large forearc basin in the late Mesozoic, was affected by both compressional and extensional tectonics in the Paleogene, and underwent a final episode of subsidence and infilling during the Neogene under the influence of strike-slip deformation associated with the North American-Pacific plate boundary. During the Neogene, thick diatomaceous oil-prone source rocks of upper Miocene Monterey Formation were deposited in the southern part of the basin, underwent subsidence and diagenesis, and generated large volumes of hydrocarbons. Numerous and thick sandstone bodies are interbedded with the diatomaceous strata and form the principal reservoirs. Shelfal clastic units surround the basin on the east, south, southwest, and north. Large submarine canyons were cut across the shelves, probably during lowstand periods, and funneled sands basinward, where thick sand-rich submarine fans accumulated. During the Pliocene, shallow-marine and intertidal conditions were more prevalent throughout the basin, as it was gradually cut off from the Pacific Ocean. During the Pleistocene, thick nonmarine strata were deposited in the basin, dominated by fluvial, lacustrine, alluvial-fan, and fan-delta depositional systems of the Tulare Formation and related units. The basin continues to undergo subsidence in its axial portions, concurrently with uplift along the western, southern, and eastern margins. The Midway-Sunset Oil Field and adjacent Temblor Range are present along the southwestern flank of the basin. A series of syndepositionally active folds in this area locally confined upper Miocene shallow- to deep-marine sandstones of the Monterey Formation, yielding numerous structural and stratigraphic traps. Uplift related to strike-slip motion along the San Andreas fault along the western flank of the basin generated numerous post-Miocene unconformities and additional traps for Miocene, Pliocene, and Pleistocene reservoirs.

The Midway-Sunset Oil Field brea was being used by the Yokut Indians long before it was described by promoters in the late nineteeth century. The first known oil well was drilled sometime around 1887 and produced heavy oil from the Tulare Formation. The field was first reported on from a technical perspective by Watts (1894). Detailed reports on the geology and natural resources of the field soon followed (Arnold and Johnson, 1910; Pack, 1920). The history of the pioneer oil companies active in the field is both varied and colorful. Burgeoning infrastructures dealing with water lines, pipelines and railroads played important roles in the field’s early development. Water intrusion concerns in the field lead to the creation of an Advisory Board to solve operator disputes that later evolved into the California Division of Oil and Gas. More than 100 gushers roared in between the years of 1909 and 1912 greatly increasing the field’s daily oil production. Modification of new technologies of the day in the areas of rotary drilling, cementing, and electric logging are still in use today.

The Midway-Sunset Oil Field produces primarily from Neogene sands and gravels which are found within the upper Monterey Formation, the Reef Ridge Shale, the Etchegoin Formation, the San Joaquin Formation and the lower and middle Tulare Formation. Age dates based on radiometric and paleontological analyses suggest that these producing horizons range in age from about 8.9 Ma (late early Mohnian) to about 1.0 Ma (Pleistocene).

The Midway-Sunset Oil Field is located along the southwest edge of the San Joaquin Valley forming a 25 mile long and three mile wide field along the northeast-flank of the Temblor Range by the town of Taft. In 1995, the field’s average production was 163,400 BOPD mostly from steam enhanced recovery making it the largest producing field in the contiguous United States. Cumulative production through 1995 was 2.3 billion barrels of oil and 563 billion cubic feet of gas. The producing reservoirs are upper Miocene, Pliocene and Pleistocene age. The Miocene reservoirs are deep submarine fan sandstones encapsulated in diatomaceous mudstones which act as a source rock, a seal and as a fractured reservoir depending upon depth of burial. Diagenesis alters diatomite (opal-A) to a porcellanite (opal-CT) at 2000± feet and finally to a chert (quartz) at 5600± feet. The submarine fans were sourced by the Gabilan Range on the Salinian block (now 150 miles to the northwest) across the right lateral San Andreas fault. Northeast transport of debris and turbidity flows into the San Joaquin basin created time-transgressive submarine fans stepping to the northwest with migration of the Gabilan Range. Seismic events were probably a major cause of shelf and slope sediment failure creating landslides, debris and turbidite flows. Transpression and wrench tectonics along the San Andreas fault modified the San Joaquin basin margin slope into a series of northwest-trending folds (e.g., Buena Vista, Globe, South Belgian and Midway anticlines) with intraslope basins (synforms) affecting submarine fan morphology. Thick sandstone deposition was restricted to the intervening synclines (e.g., Midway syncline) and anticlinal saddles. Turbidites thinned or pinched out over anticlinal crests. Late Miocene uplift of the Temblor Range accelerated folding and submarine fan deposition. Northeastward-tilt of the Temblor anticlinorium subjected portions of the Miocene to erosion. Several Pliocene transgressions with intervening erosions deposited southwestwardonlapping shallow marine sequences of sandstones, siltstones and mudstones. Continued growth of the Temblors eroded both Miocene and Pliocene rocks depositing northeast-directed alluvial fans, braided stream, and lacustrine shoreline sandstones and mudstones prograding across the Midway syncline and Buena Vista and Globe anticlines. Oil is trapped by anticlinal four way closures as pinch outs across anticlinal noses and flanks, underneath angular unconformities and as fluid level traps. Miocene oil saturated diatomites are trapped anticlinally or under Pliocene unconformities and are sand frac’d (and steamed if heavy oil) to economically produce. The deeper buried naturally fractured opal-CT diatomaceous mudstones produce along anticlines. Pliocene and Pleistocene oil is trapped anticlinally as onlap pinchouts, underneath unconformities and as fluid level traps. The shallow Miocene, Pliocene and Pleistocene sandstone reservoirs contain heavy oil, thermally recovered by cyclic steam, steam drive and fireflood from more than 9600 producing wells. Estimated reserves of 454 million barrels of oil remain to be recovered.

The Temblor Range at the southwestern margin of the San Joaquin Valley is underlain by a diverse suite of Upper Cretaceous to Recent strata that record a complex succession of paleogeographic and paleotectonic events. A series of large, generally anticlinal oil fields, including the Midway-Sunset Oil Field, lie along the northeastern margin or northeast of the range. Because production in these fields is largely from clastic reservoirs that crop out to varying extents in the range, the geology of the Temblor Range has been the subject of a great number of previous published and unpublished studies that include field mapping, structure, stratigraphy, paleontology, sedimentology, and related disciplines. The new geologic map released in conjunction with this field trip guidebook as Plate 1 covers the portion of the range marginal to the northern Midway-Sunset Oil Field and covers only post-lower Miocene strata. These units include the Miocene Monterey Formation, the Pliocene and Pleistocene Tulare Formation, and diverse Quaternary nonmarine deposits. The Monterey Formation includes a succession of diatomaceous shales, altered diagenetically to varying mineralogies, and a number of sandstone bodies that appear to have been deposited as submarine canyons and submarine fans. The Tulare Formation rests with angular unconformity on the Monterey Formation and consists in outcrop of alluvial-fan deposits derived from erosion of the Temblor Range. A large number of generally northwest-trending folds are present in the mapped area and a few minor faults.

The upper Miocene Monterey shale units of the Midway-Sunset field and the San Joaquin basin are the main source rocks for many of the oil producing formations. The Monterey Formation is derived from diatom frustules making the rocks rich in biogenic silica. The four siliceous members of the Monterey Formation in Midway-Sunset are the McDonald, Antelope, Belridge, and Reef Ridge shales with the entire section being over 5000 feet thick and interbedded with the Williams, Republic, Spellacy, and Potter sandstones. These siliceous rocks are found as unaltered amo rphous opal-A, and its diagenetic equivalents of opal-CT and quartz. The rock is characterized by porosities ranging from 70-10% and permeabilites less than 0.1 millidarcy. Since 1978, the members of the Monterey Formation have become major producing reservoirs on the west side of the San Joaquin basin as a result of hydraulic fracturing and/or cyclic steaming. Commercial production was established at Midway-Sunset by Santa Fe Energy Resources in 1985 in the Reef Ridge Shale and to date over 160 wells have been drilled to develop this reservoir. At least seven other areas in Midway-Sunset have had drilling and completion attempts aimed towards establishing commercial potential with mixed results to date from Miocene Shales.

During the late Miocene, 8.9 to 7.6 Ma, the Gabilan Range shed sediments northeast of the San Andreas fault as debris and turbidity flows depositing eight submarine-fan complexes in the southwestern San Joaquin basin encapsulated within the diatomaceous Antelope Shale Member of the Monterey Formation at Midway-Sunset Oil Field (a major mechanism causing these turbidity flows was probably movement along the San Andreas fault, in other words, the flows were seismically induced). The fans were generally timetransgressive northwestward, as the Gabilan Range was transported right laterally. The larger submarine fan members of the Monterey Formation in ascending stratigraphic order, are the Leutholtz-Metson, Williams, and Republic Sandstone Members. Minor submarine fans sourced from the southern Gabilan Range and deposited synchronously with Republic Sandstone Member deposition are the Sub-Moco, Moco T, Obispo, Uvigerina "C" and Rass. The fan morphology was controlled by 1) sand and gravel rich turbidites quickly depositing, thick sand lobes, 2) syndepositional growth folds with thicker sandstones being restricted to intraslope basin synforms, 3) lateral fan deposition, time- transgressively, due to convex fan shape and poor levees, 4) limited sediment supply between seismic and other triggering events, and 5) upper slope channel switching. The Antelope Shale sandstones are arkosic in composition, fine to coarse grained, and locally conglomeratic, depending upon whether distal, mid or proximal in original fan location. At Midway-Sunset Oil Field these submarine fan sandstones have produced more than 80 million barrels of Monterey Formation sourced oils from anticlinal, pinchout, truncation and fluid level traps.

The Midway-Sunset Oil Field lies along the tectonically active western margin of the southern San Joaquin basin, only 6-7 mi (9.6-11.2 km) east of the western edge of the North American plate. Upper Miocene Spellacy coarse clastics were derived from a granitic source located nearby to the southwest. Poorly sorted conglomerates and arkosic sands were transported through canyons cutting the upper slope and were deposited by sediment gravity flows in a deep water, intra-slope environment that was actively folding. The flows typically deposited normally graded and amalgamated beds that form hydrocarbon-bearing sandstone bodies with high porosities (23-34%) and high horizontal permeabilities (500-4,000 md). Spellacy reservoirs at Midway-Sunset field produce significant quantities of typically heavy (11-14° API) oil from shallow depths. After more than 90 years of production, many Spellacy reservoirs are still in the process of being developed by delineation and infill drilling. Well spacings of 5/8 acre (165 ft / 50 m apart) are common in spite of the high reservoir quality because of both highviscosity oil and low reservoir pressures. Thermal stimulation has been used extensively since the mid-1960’s to increase production rates.

The upper Miocene Potter sandstone reservoir of the Santa Margarita member of the Monterey Formation was deposited in deep water as a coalesced turbidite fan along the west flank of the present day San Joaquin Valley. Contributing over 35 percent of the cumulative production of the giant Midway-Sunset Field, this reservoir is currently producing more than one half of the field’s daily production of 162,000 barrels of oil per day (BOPD). Thermally enhanced oil recovery (TEOR) techniques are routinely used to produce the heavy, viscous oil in these steeply dipping sand packages where gravity drainage is a key factor. Producing since 1910, the field development practices have progressed from conventional primary to cyclic steam to steamflooding and includes some active fire floods. The dynamic continually changing reservoir conditions, due to these recovery processes, add complexity to formation evaluations. With the advent of horizontal drilling this reservoir has been and continues to be one of the most significant at Midway-Sunset Field

Although the Etchegoin Formation is considered to be Pliocene in age, K-Ar and 87 Sr/86 dating indicates that the lower part of the formation may be of late Miocene age. Molluscan fauna and foraminiferal assemblages indicate it was deposited in shallow-marine to intertidal and estuarine environments. Trapping of oil in the Etchegoin is caused by the pinchout or truncation of individual sandstone members often against the flanks of anticlines. The Etchegoin Formation produced most of the first one billion barrels of Midway-Sunset’s 2.4 billion barrels of cumulative oil production indicating much future potential remains.

The San Joaquin Formation is the youngest unit of the upper Miocene and Pliocene Etchegoin Group and provides a record of the late Neogene history of the San Joaquin basin. During Pliocene time, the San Joaquin basin had become an inland sea that was connected to the Pacific Ocean through a narrow strait along the western side of the basin. The Pliocene San Joaquin Formation unconformably overlies the Etchegoin Formation and underlies conformably to unconformably the Tulare Formation. At Midway-Sunset, the San Joaquin Formation ranges in thickness from 150 ft in the north to 1100 ft in the south. It is divided into two main zones, the Mya (Mya Tar) and Top Oil (Scalez). The reservoirs deposits are clay-rich, very fine to fine grained sandstones alternating with siltstone and claystone. Fossil assemblages indicate shallow water deposition with alternating brackish and freshwater conditions. Production from the San Joaquin Formation, at the Midway-Sunset field, is minor with production figures not available because it has been commingled with production from the Etchegoin and Tulare Formations. The oil is 12° to 28° API gravity and is found in both stratigraphic and structural traps. San Joaquin Formation oil production at Midway-Sunset field has been maintained in part by use of waterflooding and steamflooding since 1965.

The Tulare Formation at Midway-Sunset field is a complex oil reservoir with a production history as old as the field itself. Pliocene and Pleistocene in age, The Tulare consists of conglomerates, sands, and shales deposited in arid alluvial fan to lacustrine paleoenvironments. The Tulare is divided into upper, middle and lower members based on log character. To date, the lower member has provided the bulk of production from the Tulare. Productive units tend to be of high quality yet discontinuous. Oils from the Tulare are heavy with wide ranges of gravity and viscosity. Cyclic steam injection is the most common EOR application, however, flood-type applications still hold somefuture potential.

Many significant advances in horizontal drilling and production technology have occurred during the past decade. Although horizontal wells still comprise a small fraction of the total number of wells drilled annually at Midway-Sunset field, their number has been steadily increasing as more companies find specific production opportunities where this technology can be economically applied.

In 1991 and 1993 two seismic surveys were acquired across and in the vicinity of the Midway-Sunset Oil Field. High quality imaging has been difficult to obtain due to noise from the thousands of pumping wells, and steamflood operations associated with the field. Complex subsurface structure has also contributed to the problem. This paper discusses the acquisition and processing history of these surveys and the numerous methods applied to analyze and to reduce the effects of "production" noise. Also, discussed is the application of a mini-3D processing technique on one test line. This technique has provided results indicating that imaging quality of a 3D survey may be substantially su- perior to that of comparable 2D data.

Although steam injection is widely used in hydrocarbon extraction, little is known of the effects of steam on reservoir properties. This study documents mineralogic changes resulting from cyclic steam injection into the Potter sand (upper Miocene) at Midway-Sunset field. Samples were obtained from two cores recovered from wells located 200 m (650 ft) apart on the 120-acre ARCO Anderson-Goodwin lease, Section 21, T31S/R22E (Fig. 1). This lease is located on the northwest edge of Midway-Sunset field (the reader is referred to the Introduction in this publication and R. L. Gardiner’s article on the Potter for general location maps for this lease). The first well was drilled in 1984 prior to initiation of cyclic steam injection; the second well was drilled in 1991 following cumulative injection of 1,000,000 bbls of steam.

Basic core analysis is one of the few methods available for directly measuring data used to evaluate reservoir potential. Data generated are complemented by and a basis for calibration and correlation of other evaluation methods. Since these data are frequently used as "ground truth," an understanding of the analytical techniques used for heavy oil reservoirs is important in the selection of proper analysis for obtaining valid data. It should be noted, although not addressed, that proper core recovery and handling procedures are critical to the quality of data generated in the laboratory. Although the basic principles of analysis have not changed over time, the tools and techniques used have evolved, having adapted to the needs presented by the different types of oil and formations encountered. Any use of historical data should be done with a knowledge of this evolution. Although some discussion of limitations of past techniques will be made, this article will primarily discuss current methods used to determine basic data on both rock and contained fluids for different types of formations encountered in heavy oil reservoirs.

Thermal recovery is defined as a process in which heat is introduced intentionally into a subsurface accumulation of organic compounds for the purpose of recovering fuels through wells. Thousands of papers and articles have been published since 1865 on the introduction of heat into subsurface reservoirs to improve or accelerate oil recovery. This literature reflects the great variety of ways in which thermal energy has been and is being used or considered to solve or improve many different types of problems associated with the production of oil. Thermal recovery is used in preference to other recovery methods for a number of reasons. In the case of viscous oils, which is the case of most current interest, heat is used to improve the displacement and recovery efficiencies. The reduction in crude oil viscosity that accompanies a temperature increase not only allows the oil to flow more freely but also results in a more favorable mobility ratio. This discussion emphasizes the reservoir aspects of conventional thermal recovery processes - combustion, steam, hot water, and hot gases.