Oil Reservoir Conditions Research Articles

Effect of oilfield chemicals on the cloud point of nonionic surfactants

An experimental study was conducted to assess the effect of various oilfield chemicals on the cloud point of nonionic surfactants of the Triton-X series. The effects of simple salts, alkalis, acids, polymers, scale and corrosion inhibitors, biocides, a mutual solvent and a crude oil on the cloud point of several nonionic surfactants were examined over a wide range of parameters. The study also included evaluation of several additives, including short-chain alcohols, urea, and anionic surfactants, to raise the cloud point of these surfactants under oil reservoir conditions. The results obtained in this study indicated that oilfield chemicals affect the cloud point of nonionic surfactants, and the effect depends on the number of ethylene oxide groups, n, of the surfactant. At acid concentrations greater than 1 wt.%, hydrochloric or acetic acid increased the cloud point of nonionic surfactants having n > 7, with a higher cloud point being obtained with hydrochloric acid. Alkalis caused a sharp drop in the cloud point of nonionic surfactants. This effect was enhanced in the presence of sodium chloride. Anionic and cationic polymers depressed the cloud point of nonionic surfactants. Addition of an anionic polymer to alkaline solutions of TX-100 resulted in a further drop in the cloud point. Addition of urea or methanol increased the cloud point of nonionic surfactants having n > 7. Sodium dodecyl sulfate (SDS) raised the cloud point of neutral and alkaline solutions of TX-100 at low sodium chloride concentrations only. SDS also raised the cloud point of TX-45 ( n = 5) at SDS concentrations greater than 0.8 wt.%. The effect of mutual solvent on the cloud point of the four nonionic surfactants depended on the concentration of the mutual solvent and the number of ethylene groups in the surfactant.

A nuclear imaging technique for studying multiphase flow in a porous medium at oil reservoir conditions

A long core flow-rig operating at reservoir pressure and temperature has been constructed for basic studies of multiphase flow in porous media. The dynamics of the fluid saturation distributions are recorded by labelling the fluid phases by nuclear tracers and detecting the gamma radiation by a movable germanium detector. Computerized automation include data acquisition and process control. Testing of the instrumentation and preliminary flow experiments indicate that the apparatus fulfills the objective of imaging the displacement processes at reservoir conditions.

An apparatus for continuous growth of microorganisms under oil reservoir conditions

Biotechnology and BioengineeringVolume 29, Issue 2 p. 289-291 Communications to the EditorFree Access An apparatus for continuous growth of microorganisms under oil reservoir conditions B. Bubela, B. Bubela Baas Becking Geobiological Laboratory, Bureau of Mineral Resources, Canberra, ACT, AustraliaSearch for more papers by this authorC. L. Labone, C. L. Labone Division of Fossil Fuels, CSIRO, Sydney, NSW AustraliaSearch for more papers by this authorC. H. Dawson, C. H. Dawson Division of Fossil Fuels, CSIRO, Sydney, NSW AustraliaSearch for more papers by this author B. Bubela, B. Bubela Baas Becking Geobiological Laboratory, Bureau of Mineral Resources, Canberra, ACT, AustraliaSearch for more papers by this authorC. L. Labone, C. L. Labone Division of Fossil Fuels, CSIRO, Sydney, NSW AustraliaSearch for more papers by this authorC. H. Dawson, C. H. Dawson Division of Fossil Fuels, CSIRO, Sydney, NSW AustraliaSearch for more papers by this author First published: 5 February 1987 https://doi.org/10.1002/bit.260290220Citations: 3AboutPDF ToolsRequest permissionExport citationAdd to favoritesTrack citation ShareShare Give accessShare full text accessShare full-text accessPlease review our Terms and Conditions of Use and check box below to share full-text version of article.I have read and accept the Wiley Online Library Terms and Conditions of UseShareable LinkUse the link below to share a full-text version of this article with your friends and colleagues. Learn more.Copy URL Share a linkShare onFacebookTwitterLinkedInRedditWechat References 1 B. Bubela, in Microbial Enhanced Oil Recovery, J. E. Zajic, Ed. (PennWell Books, Tulsa, OK, 1983), p. 1. 2 B. Bubela, Biochim. Biophys. Acta, 123, 364 (1966). Citing Literature Volume29, Issue25 February 1987Pages 289-291 ReferencesRelatedInformation

カフジおよびフート油田のダンプウォーターフラッディング

Dump water flooding is a method utilizing a cross flow within a wellbore. The dumping water is established by the difference of flow potentials between a natural aquifer as a water source and an oil reservoir. Therefore, once the perforation is made into the both of aquifer and oil reservoir and the potential of aquifer is kept higher than that of the oil reservoir, water is continuously injected without any artificial drive. Obviously, the simple nature of the method indicates extreme dominance in economy. However, the injection performance is very sensitive with the conditions of aquifer and oil reservoir. Accordingly, the applicability of the method is highly limited. In the first part, the basic mechanism of dump water flooding is presented and the advantage and disadvantage of the method are briefly discussed. In the latter part, the examples of three projects in Khafji and Hout fields, Saudi Arabia are presented and the keys to the successful operation are briefly discussed.

The M6 Steam Drive Project Design And Implementation

Abstract The M-6 steam drive project is located in the Tia Juana field, Bolivar Coast, Venezuela and is scheduled to go on stream towards the end of 1977. Primary production started in 1948 followed by a period of stea1n soak from 1969 onwards. Steam soak is favoured by the compaction process. At the start of steam drive it is estimated that the remaining reserves by compaction is some 4% STOIIP compared to a total recovery by comparison of some 20% STOIIP. The past performance amt the prediction of future performance will be discussed on the basis of the results obtained from an earlier, smaller scale steam drive project, laboratory investigations on physical models and compaction drive theory. During 1975 and 1976 an extensive programme of data gathering in the field and special production/ injection tests in wells were carried out, and a detailed geological/petrophysical study is being made. In three inverted seven spots steam is being injected continuously, the first hexagon started in November 1975 and the other two in July and August 1976. Tracers in the gaseous and aqueous phase have been injected to detect preferential flow. The results of these tests a1'e discussed. Introduction The heavy oil fields on the eastern coast of Lake Maracaibo (see Figure 1) - known as the Bolivar Coast -initially contained some 33.8 billion barrels of oil-in-place, of which only about 11% can be recovered by primary means; this figure represents an average which comprises 0% recovery for the very viscous crudes (up to 50,000 cp) in North Tia Juana, 6–7 %, in the Upper Lagunillas Heavy and up to 20% in the coastal areas. The current proven and possible reserves by primary and steam soak production is on average 18% STOIIP, therefore leaving in the ground some 28 billion barrels of oil as a vast potential for additional recovery methods. Since 1959 various methods have been tested, such as steam drive 1,3, in-situ, combustion2 and steam soak.4,5. Reservoir compaction is the main production mechanism in the Bolivar Coast reservoirs. It is proposed to make full use of this natural source of energy by applying the steam soak process. When compaction reserves are exhausted, other drive processes will be applied; the most appropriate being steam drive based on pilot tests. The M-6 steam drive is intended to evaluate the application of this recovery method on a large scale as the follow-up process for the Bolivar Coast after steam soak. Based on the results of laboratory experiments and the performance analysis of the C-3/C-4 steam drive test, discussed below, the large scale M-6 steam drive project has been designed. LABORATORY MODEL EXPERIMENTS Physical model studies were undertaken in 1971 in the Koninklijke/Shell Laboratorium. Rijswijk, the Netherlands, to obtain additional technical information on the steam drive process under Bolivar Coast heavy oil reservoir conditions. The investigations took place in one twelfth of an inverted seven spot proto-type (closed hexagon) with a distance of 230 m from corner well to centre injection well.

Subsurface Geology and Oil Possibilities at Southwestern Part of Mt. Chookai

Southwestern Part of Mt. Chookai where is covered with its lavas and detritus, has been explorated by geophysic methods and wells these few years. Results of exploration are outlinedin followings; (1) Oil accumulation and reservoir conditions in Fukra field were controlled by sea bottom high which had existed during Tentokuji grey mudstone depoisted. (2) At Masukawa, Katsurane alternated facies quickly change its thickness from north to south. It is presumable that warping or arching actions occurred in late Tentokuji in this district. (3) From studies of stratigraphic sections, it is reasonably expected that oil have accumulated in Katsurane formation at Higashi-Fukura, westside of Masukawa, and in Katsurane, Funakawa and Onnagawa formations near nakamura, eastside of Masukawa.

Marine Bank Development in Plattsburg Limestone (Upper Pennsylvanian) in Neodesha-Fredonia Area, Southeastern Kansas: ABSTRACT

The Plattsburg limestone is anomalously thick in the Neodesha-Fredonia area, swelling from less than 10 feet to maximum thickness of 115 feet. Thickening is due to large increases in thickness of two of the three members into which the Plattsburg has been divided. The Merriam limestone (lower member) varies only slightly in thickness, ranging from 1 to 3 feet, but the Hickory Creek shale (middle member) ranges from 1 to 45 feet, and the Spring Hill limestone (upper member) ranges from 3 to 88 feet in thickness. The principal cause of thickening of the Plattsburg limestone is interpreted to be due to deposition of an extensive, lens-shaped shallow marine bank which rose above the general level of the surrounding sea floor. The shape of the bank is thought to be partly reflected by present thickness variations in the Plattsburg limestone. The bank was at least 14 miles long northwest and southeast, and about 12 miles wide northeast and southwest. End_Page 127------------------------------ Two smaller, detached thickened parts of the Plattsburg limestone are also present in the area and probably represent small banks. A second cause of thickness variations in the Plattsburg limestone is local structural warping during deposition, which permitted greater thicknesses to accumulate over downwarps and less thicknesses over upwarps. Thickness of the Vilas shale also has been affected by this cause. Thickness of the Vilas shale has been observed to be inversely related to thickness of the Plattsburg limestone at most localities where the two formations are exposed. Where the Plattsburg limestone is thick, the Vilas shale tends to be thin, and vice versa. The Vilas shale has been interpreted to be an off-bank lateral time equivalent of the thickened Spring Hill member. Deposition of the bank is interpreted to have been strongly influenced by carbonate-secreting organisms, including crinoids, bryozoans, brachiopods, mollusks, and algae, which flourished over the bank. The organisms may have influenced deposition of silt and clay (Hickory Creek shale member) by exerting a sediment-binding effect, and probably helped stabilize slopes at least as great as 7° on the sides of the bank. In addition, the carbonate-secreting organism contributed large quantities of calcareous material to form the upper part (Spring Hill limestone member) of the bank. Where thick, the Spring Hill limestone member of the Plattsburg may be divided into three tabular lithologic subdivisions which occur in regular vertical sequence. The lower subdivision has been termed the fragment-pellet subdivision because of the abundance of irregular-shaped fragments and pellets. Much of the fragmental and pelletal material appears to be of algal origin. The middle subdivision is termed the crystalline subdivision because of the abundance of sparry calcite which is closely associated with fragments of carbonate encrusted blades of various forms of calcareous algae. Some of the algal forms resemble the alga Anchicodium, although positive identifications have not been made because of the lack of preservation of essential details. The upper subdivision is termed the alcarenite subdivision because of the abundance of calcarenite composed of grains with varying degrees of rounding and sorting. During deposition of the crystalline limestone subdivision of the Spring Hill member, carbonate-secreting algae may have imparted sufficient rigidity to the bank to cause it to be wave-resistant and thus allowing it to be classed as a reef. However, during deposition of most of the other parts of the Plattsburg bank, the deposits probably did not possess sufficient coherence to be wave-resistant. Porosity in the Spring Hill member in outcrops is closely related to limestone lithology. Highest porosity occurs in the crystalline limestone subdivision, where conspicuous pores and vugs occur in visibly crystalline calcite. Some of the crystalline calcite is interpreted to have formed through precipitation in open spaces which were not filled with calcareous mud during deposition because of the sheltering effect of individual fragments of carbonate-encrusted calcareous algae. Other crystalline calcite appears to have been produced through recrystallization of calcareous algae. It seems possible that favorable oil reservoir conditions in certain Pennsylvanian limestone in central and western Kansas may be provided by porous zones in thickened limestones lenses similar in origin to t e thickened Plattsburg in the Neodesha-Fredonia area. End_of_Article - Last_Page 128------------

Some Examples of Fluid Flow Mechanism in Limestone Reservoirs

Abstract The properties of limestone reservoir rocks such as the distribution anddegree of continuity of the pore systems, and the relative volumes andpermeabilities of the systems making up the complex cause large variationsbetween performance of individual limestone reservoirs and their susceptibilityto secondary recovery methods. The effects of these factors on the mechanism offluid flow cannot be adequately evaluated with presently developed concepts, laboratory data, and geological information. The observance and interpretationof the performance of individual limestone reservoirs provides, at present, themost adequate approach for evaluating the integrated effects upon performanceof the many, now immeasurable variations in the properties of limestonereservoirs. Introduction The development and application of techniques for increasing the efficiencyof oil recovery from natural reservoirs is a problem of primary importance tothe industry. During the past several years, a great deal of effort has beenexpended by the technical personnel of the industry toward the improvement ofpresent known methods of oil recovery, and evaluating the factors which controlthe susceptibility of particular reservoir types to economic application ofsecondary recovery methods. Providing adequate and accurate laboratory data onthe properties of the reservoir rock and its contained fluids, together withgood production statistics, are available, methods have been evolved forestimating with reasonable accuracy the performance of an oil reservoir undereither continued natural depletion or conditions imposed by introducingadditional displacing fluid into the reservoir from an extraneous sourcethrough the injection of gas and/or water. The susceptibility of limestone reservoirs to secondary recovery by gasinjection is very much dependent upon gas-oil relative permeabilityrelationships for the reservoir in question. In a rock formation in which theporosity is of the intergranular type such as is found in sand stones and somenonfractured dolomites, a representative sample of the pore structure can beobtained in a small core plug. In this type of reservoir, it has been shownthat relative permeability data obtained from laboratory experiments can beproperly applied to evaluate the flow relationships actually observed duringthe depletion of a reservoir. In addition, a good idea of the fraction of thereservoir which will be swept by the injected gas may be obtained from thespacing pattern used and the permeability profile of cored wells. From thesedata, it has been demonstrated that reliable estimates of performance andrecoveries under gas injection operations can be made for reservoirs in whichthe porosity is of the intergranular type. T.P. 2638