Non-conventional Oil Research Articles

The World's Non-Conventional Oil and Gas Resources

The World's Non-Conventional Oil and Gas Resources

Worldwide Exploration Climate

Petroleum companies have entered a period of aggressive restructuring. Investment in exploration is reduced as a result of lower available cash flow and the poor results of past investments. Exploration by non-government companies is expected to remain at low growth caused in part by the massive global restructuring now underway and environmental concerns related to consumption of hydrocarbons. Exploration is geared toward the midterm expected future price of oil which is not expected to increase substantially. With limited available resources, companies are becoming much more selective in their area of focus. This, coupled with probable industry consolidation of companies, will result in a decrease in competition for new acreage. Funding will concentrate on conventional low cost plays in the areas where governments grant the best terms. High-cost oil at the margin, including Arctic, heavy oil, and deepwater areas, has become particularly vulnerable as more investments are being made in projects that survive economically under low prices. Additionally, R D funding has been reduced, thus the development of cost-effective extraction technology necessary to exploit these higher cost areas has been deferred. We must acknowledge that developing high-cost frontier or non-conventional oil is a high-risk venture that can only be pursued throughmore » efficient operations and the effective use of appropriate technology under economic terms which provide incentive and protection if prices decrease. A collaborative working partnership between host governments and industry that effectively addresses the long-term objectives of both parties is essential for these types of projects to proceed.« less

Studies on Non-conventional Oil Seeds : Search for New Sources of Edible and Industrial Oils

Studies on Non-conventional Oil Seeds : Search for New Sources of Edible and Industrial Oils

The Jobo Steamflood Project: Evaluation of Results (includes associated paper 17636 )

Summary. This paper presents a description and a preliminary evaluation ofthe Jobo steamflood project, located in eastern Venezuela, from startup inMarch 1981 through Dec. 1986. The Jobo project consists of a steamdrive atoriginal reservoir pressure conditions (1,300 psia [8–96 MPa]) because anactive aquifer supporting this reservoir prevents pressure depletion byprimary steam-stimulated production. The primary recovery estimated forthis 8.5deg. API [1.01-g/cm3] accumulation of 10% stock-tank original oil inplace (OOIP) is expected to increase to above 45% by steamflooding. Todate, 36.2% of the project's stock-tank OOIP has been produced. and steam breakthrough is expected to occur during 1988. Production and injection well completions, as well as surface equipment, were evaluated for the future commercial development of this and other extra-heavy reservoirs in Venezuela. Introduction The largest extra-heavy (8.5 deg. API [1.01-g/cm3]) oilaccumulations in the world are located in eastern Venezuela, just north of the Orinoco River in the Orinoco oil beltand neighboring reservoirs. Although the Orinoco oil beltalone has 1.2 × 10(12) bbl [190 × 10(9) m3] of oil in place, only an estimated 10% will be recovered by primarysteam-stimulated production. After several secondaryrecovery methods were analyzed, steamflooding was selected as the most effective in these reservoirs, and theJobo pilot project was designed and implemented on thebasis of a numerical simulation study. The project wascarried out in the Jobo field to make use of existing infrastructures and because reservoir and fluidscharacteristics are essentially identical to thoseprevailing in the extra-heavy oil accumulations of the Orinoco belt. Project Description Project Objectives. The Jobo project was conceived toobtain information for future commercial developmentplanning of this particular reservoir and to obtaininformation about the vast amounts of extra-heavy, nonconventional oil from the Orinoco oil belt. The mainobjectives to be accomplished are listed here.1. To determine the recovery factor. The project willbe kept at constant pressure to prevent fluid movementinto or out of the system.2. Evaluate the technical and economic feasibility ofsteamdrive at original reservoir pressure conditions. Astrong natural water drive present in the reservoirprevents pressure depletion by primary steam-stimulatedproduction, which is the routine production method.3. To evaluate surface facilities and produced-fluidstreating and handling.4. To determine optimum production and injection wellcompletions.5. To calibrate numerical simulators for best predictionsand comparison of exploitation alternatives. To ensure the acquisition of the required data and thusto evaluate the project properly, a very comprehensivetest and measurements program was designed andimplemented during each phase of the project. Furthermore, a computer(surveillance) program was developed thatperforms material and energy balances on all streams thatenter or exit the plant and that validates measured production to calculate a field factor. Location. The Jobo project is located in the Jobo field, south of the state of Monagas in eastern Venezuela. Asseen in Fig. 1, the project is adjacent to the vastextraheavy oil accumulations of the Orinoco oil belt, whichspreads over an area of 21,000 sq miles [54 000 km2]through the states of Delta Amacuro, Monagas, Anzoategui, and Guarico, just north of the Orinoco River. Geology. The Jobo field reservoirs belong to the Oficinaformation, which is divided into the Pilon, Jobo, Yabo, and Morichal members, as shown in the stratigraphicsection of Fig. 2. The project is in Sand C of the Morichalmember. The sand's quality and thickness make it the bestobjective sand. These sands were deposited during theLower to Middle Miocene Age in a transgressive/regressive, shallow marine to fluvio-deltaic environment. Thegeneral structure corresponds to a monocline orientedeast/west and gently dipping (3 deg. [0.05 rad]) north. Anupstructure location was selected primarily to minimizewater encroachment from an active aquifer in the reservoir. Also, best-quality sands (clean and horizontallycontinuous)and fewer well completions (relatively virginzone) are characteristics of this zone: therefore, resultsof the project will not be affected by external influencesor heterogeneities and should be easier to interpret. These sands are composed mainly of quartz with onlyabout 7% clays, kaolinite being the predominant claymineral with only traces of illite and smectite. Althoughkaolinite belongs to the group of clays that do not swellby water absorption. JPT P. 1261^

Industrial applications of electrolytic hydrogen (EH 2)

While the potential applications of EH 2 on an industrial scale cover a wide variety, including chemicals, metallurgy, petroleum upgrading, synfuel production, heating and transportation, it is likely that the earliest applications will be those for which the hydrogen end-use technology is already in place, or nearly so, and which are of widespread interest throughout the world—notably ammonia-based fertilizers, methanol production, and heavy and non-conventional oil upgrading. This paper examines such major applications with particular attention to optimum use of the cogenerated electrolytic oxygen, the technology required and the anticipated economics under various conditions.

Abandoned Oil Fields of Texas Gulf Coast: ABSTRACT

One nonconventional oil target in Texas is the oil that remains in abandoned fields, defined as those fields that had no oil or gas production in 1977 and 1982. This target includes oil that has not been tapped by conventional field development because of reservoir heterogeneity and oil in reservoirs that have not been subjected to any secondary or tertiary recovery efforts. A total of 138 abandoned oil fields having individual cumulative production greater than 500,000 bbl are located in the Texas Gulf Coast (Railroad Commission of Texas Districts 2, 3, and 4). These 138 onshore fields produced 276 million barrels of oil before being abandoned. Nongiant fields in the Texas Gulf Coast average about 40% ultimate recovery, so these fields probably originally contained about 700 million bbl of oil in place. Therefore, about 424 million bbl of oil remain unrecovered. End_Page 472------------------------------ Reservoirs in these abandoned fields are Tertiary sandstones. The 44 abandoned fields in the upper Texas Gulf Coast (District 3) produced from a wide range of plays; those plays with the largest number of abandoned fields are Yegua and Frio deep-seated domes, Eocene deltaic sandstone, and Frio barrier/strand-plain sandstone. The 19 abandoned fields in the middle Texas Gulf Coast (District 2) produced mainly from Wilcox and Frio fluvial/deltaic sandstones and from Frio and Jackson-Yegua barrier/strand-plain sandstones. The lower Texas Gulf Coast (District 4) contains 75 abandoned fields that produced from Frio fluvial/deltaic and barrier/strand-plain sandstones and from Jackson-Yegua barrier/strand-plain sandstones. End_of_Article - Last_Page 473------------

Colloid and Surface Chemical Problems in Non-Conventional Heavy Oil Recovery

Abstract Although emulsions have always been a problem for the petroleum industry, the producing of heavy crude oil can be further complicated by the presence of colloidal clays and asphaltenes which create a new type of emulsion. This phenomenon became apparent recently in the " Hot Water Process" for extracting bitumen from the Athabasca Tar Sands. The clays form membranous skins at the oil water interface which do not respond to conventional emulsion- breaking procedures. Caustic pH ranges, polyphosphates and other dispersing agents, rather than cationic flocculating, should be used to overcome this problem. Asphaltenes are colloidal crude oil constituents which also have the ability to form skins at the oil-water interface. These skins stabilize water in oil emulsions which do respond to conventional emulsion-breaking procedures. The asphaltenes contain very strongly polar chemical compounds, thus emulsion treating requires relatively high concentrations of expensive chemicals. A pH adjustment can reduce these requirements. Our Alberta heavy oils contain approximately 20 per cent asphaltenes, which, therefore, constitute a potential problem. The resinous acids in our heavy oils form another group of surface-active compounds. They stabilize water in oil emulsions, which can be broken more easily by conventional means. One other aspect of the resinous acids is their ability to form water-soluble soaps in the presence of caustic. Theoretically, these soaps could promote improved oil recovery. However, most of our heavy oil reservoirs contain clays which adsorb caustic and prevent this soap formation. The benefits observed due to caustic injection are believed to be due to the dispersion of the clays rather than the formation of soaps.