Oil-saturated Zones Research Articles

Integrated fracture analysis for improved oil recovery in the reefal limestones of Soğucak formation, Northwest Thrace Basin, Türkiye

Natural fractures play a crucial role in both exploration and development phases in oil and gas industry, as their network and orientation significantly affect flow and recovery strategies. This study highlights the importance of identifying opening-mode fracture systems within a mature Deveçatağı oil field that has been actively producing for nearly half a century. In order to investigate the most effective rock physics parameter to locate oil saturated zones in the field, this study applies detailed rock physics analysis and 2D forward modeling to pinpoint the principal factors affecting production in the Deveçatağı oil field, addressing the challenge posed by the limited shear wave wireline data acquired from only one well within this highly heterogeneous area. Analysis show that acoustic impedance is a crucial elastic property for detecting oil-saturated zones especially in areas with natural fractures. This study successfully integrates drilling-induced fracture (DIF) data, ant tracking maps, and seismic inversion outputs to understand on the issues leading to dry wells and advances in developing more effective exploration and recovery methods in fractured reservoirs. After almost 50 years of operational activities, well stimulation processes, and natural fractures that are present in this field, understanding oil drainage mechanisms in such environments is complex, emphasizing the need for comprehensive analysis to optimize production strategies.

Review of oil recovery techniques using foam systems

The article provides an overview of enhanced oil recovery methods based on the injection of foam systems. In late-stage fields developing, it is necessary to block highly permeable watered formation zones. For this purpose, the use of foaming systems is promising. As a result of blocking high-permeability zones with foam systems, lowpermeability oil-saturated zones are involved in the development. The article considers the foaming mechanism, selection of foam stabilizers, foam migration in the formation. The influence of temperature, mineralization of formation water, the presence of oil on the stability of foam systems are investigated in this review. Experimental studies and field implementation indicate that technologies are very effective. Foam flooding increases the coverage efficiency in heterogeneous reservoirs, thereby increasing the oil recovery ratio. Investigations into this matter are therefore urgent and still ongoing today. Keywords: foaming systems; stability; polymer; nanoparticles; microphotographs; salinity; displacement ratio; formation coverage; self-generating thermal foams; fractured reservoirs.

Water-free oil reservoirs: origin and morphology

The features of the morphology and composition of secondary minerals in the reservoir zones of the White Tiger (Bach Ho) deposit (shelf of South Vietnam) and deposits in clay rocks of the Bazhenov formation of the Salym area of Western Siberia are considered. It is shown that the common for these fields is the formation of a reservoir as a result of the leaching effect of high-temperature fluids. The genesis of the reservoir is determined by a complex of secondary minerals, obviously of hydrothermal origin, partially filling caverns and cracks in the rock: native silver – zincous copper – barite – anhydrite – kaolinite – laumontite (White Tiger oilfield) and sulphates of iron, aluminum, sodium and calcium – iron-aluminum alum, alunite, jarosite, mirabilite, melanterite, gypsum (deposit in the rocks of the Bazhenov formation of the Salym area). Diagnostics of secondary minerals was established based on the results of microprobe studies of undisturbed samples and analysis of the composition of water extracts from crushed core samples.The species composition of secondary minerals indicates a high temperature of the affected solutions, which varied from 600 to 200°C in the case of the White Tiger oilfield, and in the range of 350–450°C, in the case of rocks of the Bazhenov formation. Hydrothermal alteration of crystalline rocks with the formation of secondary clay minerals (kaolinite, montmorillonite, hydromica), zeolites and minerals-sulfates, which are crystalline hydrates, occurs with the absorption of huge amounts of water by the rock (up to 4∙108 tons of water per 1 km3 of altered rock). This may be related to the waterlessness (lack of bottom water) of oilfields, the reservoir of which has a hydrothermal origin. It is possible that oil deposits in crystalline rocks with high oil-saturated zones have associated waters of hydrothermal rather than sedimentogenic origin, but they occur at considerable depths and are not penetrated by drilling. This possibility is evidenced by the discovery of hydrothermal water in the basement of the White Tiger reservoir at a depth of 4493 m, which, in terms of chemical composition and mineralization, is close to the waters of sodium chloride hydrotherms of Kamchatka.

Microbially Induced Calcium Carbonate Plugging for Enhanced Oil Recovery

Plugging high-permeability zones within oil reservoirs is a straightforward approach to enhance oil recovery by diverting waterflooding fluids through the lower-permeability oil-saturated zones and thereby increase hydrocarbon displacement by improvements in sweep efficiency. Sporosarcina pasteurii (ATCC 11859) is a nitrogen-circulating bacterium capable of precipitating calcium carbonate given a calcium ion source and urea. This microbially induced carbonate precipitation (MICP) is able to infill the pore spaces of the porous medium and thus can act as a potential microbial plugging agent for enhancing sweep efficiency. The following explores the microscopic characteristics of MICP-plugging and its effectiveness in permeability reduction. We fabricate artificial rock cores composed of Ottawa sand with three separate grain-size fractions which represent large (40/60 mesh sand), intermediate (60/80 mesh sand), and small (80/120 mesh sand) pore sizes. The results indicate a significant reduction in permeability after only short periods of MICP treatment. Specifically, after eight cycles of microbial treatment (about four days), the permeability for the artificial cores representing large, intermediate, and small pore size maximally drop to 47%, 32%, and 16% of individual initial permeabilities. X-ray diffraction (XRD) indicates that most of the generated calcium carbonate crystals occur as vaterite with only a small amount of calcite. Imaging by SEM indicates that the pore wall is coated by a calcium carbonate film with crystals of vaterite and calcite scattered on the pore wall and acting to effectively plug the pore space. The distribution pattern and morphology of microbially mediated CaCO3 indicate that MICP has a higher efficiency in plugging pores compared with extracellular polymeric substances (EPSs) which are currently the primary microbial plugging agent used to enhance sweep efficiency.

Study on influence of two-phase filtration transformation on formation of zones of undeveloped oil reserves

In order to study the process of fluid filtration during flooding of an oil field, article uses Rapoport – Lis model of non-piston oil displacement by water. During plane-radial filtration in a homogeneous formation, radii of disturbance zones are determined with and without taking into account the end effect. Influence of changes in value of capillary pressure gradient on distribution of water saturation coefficient in the non-piston displacement zone for high and low permeability reservoirs is revealed. Application of an element model for a five-point injection and production well placement system showed that, using traditional flooding technology, flat-radial fluid filtration is transformed into rectilinear-parallel. At solving equation of water saturation, Barenblatt method of integral relations was used, which allows determining the transformation time. By solving the saturation equation for rectilinear-parallel filtration, change in the value of water saturation coefficient at bottomhole of production well for an unlimited and closed deposit is determined. It is shown that an increase in water cut coefficient of a production well is possible only for a closed formation. To determine coefficient of water saturation in a closed deposit, a differential equation with variable coefficients is obtained, an iterative solution method is proposed. In the element of the five-point system, oil-saturated zones not covered by development were identified. For channels of low filtration resistance, conditions for their location in horizontal and vertical planes are established. It is shown that, at maintaining formation pressure, there is an isobar line in formation, corresponding to initial formation pressure, location of which determines direction of fluid crossflow rates. Intensity of crossflows affects application efficiency of hydrodynamic, physical and chemical, thermal and other methods of enhanced oil recovery.

Controlling excess water production in fractured carbonate reservoirs: chemical zonal protection design

Fractured carbonate reservoirs are prone to premature water cut production at the early stage of recovery. Conventionally completed long horizontal wells, suffering from high water cut through fracture networks, need reliable and cost-effective treatment solutions to control water entry, without damaging oil-saturated segments. Protection of oil flow channels from polymer gel invasion could be a challenge in complex fractured reservoirs because of the enormity of the number of zones that may require damage protection. In this work, a chemical package system is developed, comprising three different chemical solutions. The first fluid is designed to protect the low-permeable oil-saturated zones by creating an impermeable barrier while keeping the water conductive fractures open, followed by a gelant, designed to invade, solidify, and seal off the water conductive fractures. The third treatment is designed for a complete dissolution of the protective barrier created by the first fluid. The effectiveness of this process is evaluated through a set of four core flood studies at reservoir conditions. It was observed that whereas the effective brine permeability could be reduced by 74–91%, oil effective permeability is reduced by 12–17% depending on the fracture aperture. The paper also discusses the key parameters to be addressed for successful field implementation of this technology.

INFLUENCE ON PROCESSES MACROCOSM IN THE OIL AND GAS FIELDS

Is a brief overview on the topic of migration of hydrocarbons in the subsoil, the various factors influencing the process of flood recovery and coning in holes zones, transition zones of water zones and the oil-water contact, invasion and scattering halos. It is shown that the essential factor, not previously accounted for in the description of all these processes is the influence of the tidal humps formed by the action of the gravitational field of the Moon and the Sun, as well as irregular rotation of the Earth. That is generally not considered the impact on the local macro processes in oil and gas fields and wells. The most important factors in the rezervuar and migration of hydrocarbons in the formation of clusters of galaxies are considered the seal rocks, hydrostatic factor, gravitational forces (buoyancy of oil and gas) and of high-traps overpressure. Other factors accompany and complicate the basic forms of movement of hydrocarbons. In all conditions, the capillary processes are accompanied by a counter movement of water to oil (counter) - water is introduced by small pore channels in oil-saturated zone and oil - on major channels in zone. Summarizing a number of literary sources, scientists call the following main reasons for admission to the well bottom water: approximation of contour treatment as the selection of oil from the reservoir; bottom water coning; the channeling of the well annulus. For OWC level can be taken by some averaged value KAP is an inclined and a curved surface. PP water-oil itself has a certain length in the thickness of the formation that depends on the properties of reservoir fluids and reservoir. Oil oxidized PP is more heavy and viscous. Collector PP has inferior filtration-capacitive properties due to its bituminisation. The stability of the water zones for a long geological time, and an increasing deterioration of the reservoir permeability is possible if there is a periodic disturbing external influence on the transition zone whereby the oil and water is mixed as a result of the initiation of the main and related factors. This disturbance tidal humps are generated by the attraction of the moon and sun, as well as the changing moment of inertia due to the irregular rotation of the Earth. Naturally, these factors influence the development of processes and coning invasion halos of gas in the dome of the tires.

Low-frequency amplitude analysis for oil detection within the Middle Jurassic sediments in the southern part of Western Siberia

The structural element of a prospect is not a key factor in the detection of hydrocarbon deposits within the Jurassic formations of the southern parts of the West Siberian province. We investigated a method of mapping oil-saturated zones within the Middle Jurassic reservoirs. We evaluated the quantitative criteria between oil-saturated versus water-saturated zones. The methodology was based on amplitude analysis of seismic data and information obtained from the data and well testing.

Mathematical modeling of seismic gravity effect of oil and gas reservoir in crystalline basement

A new seismic and gravitational method for the decompacted zones detection in crystalline basement, based on a multi-crack-cavernous pore (gas or oil saturated) model of crystalline reservoir is proposed. To estimate the capabilities of the proposed method mathematical modeling of effective elastic and acoustic properties of granite reservoir rocks with different pore space structure is realized. The algorithm and software for solving the problem of joint inversion of seismic and gravimetric data based on Born's approximation for the space-time Green's function with root mean square background velocity for the horizontally-layered medium has been developed and tested. It has been determined that the most reliable estimation of density and seismic velocity can be obtained by joint inversion. Convincingly is illustrated on an example of the Prykerch shelf model that the presence of decompacted oil or gas saturated zone in granite basement can be confidently identified based on results of seismic and precise gravity observations.

Heavy-Oil Recovery by In-Situ Emulsion Formation

Summary The aim of this work is to evaluate alkaline/surfactant (AS) methods to improve recovery from heavy-oil reservoirs. Alkali/surfactant/oil phase-behavior experiments were conducted to determine conditions under which oil-in-water (O/W) emulsions form. The viscosity (and its shear dependence) was measured for some of these emulsions. Reservoir sand was assembled in sandpacks. Waterflood and AS floods were conducted at several salinities. Several relatively hydrophilic surfactants were identified, which formed O/W emulsions with the reservoir oil at a low concentration in the presence of sodium carbonate. O/W emulsions were favored at low salinity and high water/oil ratio (WOR). Viscosity of these emulsions was low compared with the oil viscosity. Waterflood recovery was on the order of 25 to 40% of the original oil in place (OOIP) in corefloods, and it decreased as the injection rate increased. Following the waterflood, the AS flood gave an incremental oil recovery of 10 to 35% of OOIP. The incremental post-breakthrough oil recovery during the waterflood is likely because of the imbibition of the water from viscous fingers into the unswept oil-saturated zone; this recovery is directly proportional to the square root of time.

Development of a novel chemical water shut-off method for fractured reservoirs: Laboratory development and verification through core flow experiments

Most of the extended reach horizontal wells and also the vertical wells with permeability heterogeneities often experience premature and excessive water production from multiple, high permeability streaks and conductive fractures. Bullhead and Relative Permeability Modifier (RPM) treatment often fails to achieve the desired result, as in most cases the situation warrants isolation and protection of the oil producing zones, from highly damaging polymeric gels. Protection of oil zones in a highly fractured reservoir is technically and economically a huge challenge because of knowledge on the complexity of fracture network. This paper describes the application of three chemical fluid compositions in sequence, as an alternate rigless water control option whose self-selectivity and effectiveness in controlling water production are verified in the laboratory in simulated fractured reservoir condition. The first fluid is designed to protect the matrix by creating an impermeable filter cake on low permeable oil saturated zones, keeping the water swept fractures open for gel treatment. The second fluid is a cross-linkable polymer gelant to shutoff the fractures and the third fluid is an enzyme breaker for cleaning the filter cakes form matrix zones. After completion of the treatments, return permeability measurement was carried out which shows 85–90% reduction of water permeability with less than 15% reduction of oil permeability. Microscopic investigations on treated core plug show very little invasion of polymer gel into the matrix area, whereas the fractures are almost completely sealed. The technology could be suitably applied without rig deployment and at a low cost. However, the fluid composition, pumping pressure and flow rate need to be customized based on the candidate well and the actual reservoir parameters.

Novel Thermal Technology Uses Two-Wellhead Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120413, ’A Novel Thermal Technology of Formation Treatment Involves Bi-Wellhead Horizontal Wells,’ by R.R. Ibatullin, SPE, N.G. Ibragimov, SPE, R.S. Khisamov, A.T. Zaripov, and M.I. Amerkhanov, Tatneft, originally prepared for the 2009 SPE Middle East Oil and Gas Show and Conference, Bahrain, 15-18 March. The Republic of Tatarstan possesses significant reserves of heavy oil and bitumen. The first pilot project on heavy-oil production through vertical wells dates back to the 1970s. A number of thermal methods were tested including in-situ combustion, cyclic-steam stimulation, and gas/steam-mixture injection. However, all these methods demonstrated their insufficiency. In 2006, a new pilot project was launched. This is a modified technology of steam stimulation through a pair of U-shaped horizontal wells. Introduction There are many applications of the steam-assisted gravity-drainage (SAGD) method in Alberta, Canada. The efficiency of the SAGD method greatly depends on the presence of water-saturated and shale interlayers in the reservoir section. In 2006, a new pilot project was launched in Ashalchinskoye field to test a modified low-pressure SAGD technology using a unique pair of U-shaped horizontal wells (two-wellhead wells) (Fig. 1). This technique overcomes some disadvantages of classic SAGD technology. This deposit occurs at approximately 78 m and has a rather complex structure. Water-saturated interlayers are found in the top and in highly oil-saturated zones of the formation, while shale stringers are found in the middle of the sequence. Both aquifers and tight, low-permeability, calcareous sandstones or a low-saturated reservoir can serve as the bottom of the formation. New Solutions To date, three pairs of U-shaped horizontal wells have been drilled in this area, with the length of horizontal wellbores from 200 to 400 m. The wells were drilled with a vertical drilling rig, hitting the surface at an angle, thus having two wellheads–vertical and slanted. Two parallel horizontal wells were completed with sand screens and were drilled one above the other at a vertical distance of 5 m between them. The process monitoring is carried out through vertical evaluation wells, and a fiber-optic cable is used for temperature measurement along the horizontal wellbore. The wells were completed by swabbing until mud and solids stopped being produced; then, steam was injected into both wells with the subsequent placing of the lower well on pump production; temperature was monitored along the wellbore length to determine lost-circulation zones and to control the profile of the wellbore heating.

Fracture-porosity inversion from P-wave AVOA data along 2D seismic lines: An example from the Austin Chalk of southeast Texas

Vertical aligned fractures can significantly enhance the horizontal permeability of a tight reservoir. Therefore, it is important to know the fracture porosity and direction in order to develop the reservoir efficiently. P-wave AVOA (amplitude variation with offset and azimuth) can be used to determine these fracture parameters. In this study, I present a method for inverting the fracture porosity from 2D P-wave seismic data. The method is based on a modeling result that shows that the anisotropic AVO (amplitude variation with offset) gradient is negative and linearly dependent on the fracture porosity in a gas-saturated reservoir, whereas the gradient is positive and linearly dependent on the fracture porosity in a liquid-saturated reservoir. This assumption is accurate as long as the crack aspect ratio is less than 0.1 and the ratio of the P-wave velocity to the S-wave velocity is greater than 1.8 — two conditions that are satisfied in most naturally fractured reservoirs. The inversion then uses the fracture strike, the crack aspect ratio, and the ratio of the P-wave velocity to the S-wave velocity to invert the fracture porosity from the anisotropic AVO gradient after inferring the fluid type from the sign of the anisotropic AVO gradient. When I applied this method to a seismic line from the oil-saturated zone of the fractured Austin Chalk of southeast Texas, I found that the inversion gave a median fracture porosity of 0.21%, which is within the fracture-porosity range commonly measured in cores from the Austin Chalk.

Geochemical characteristics and implications of hydrocarbons in reservoir rocks of Junggar Basin, China

A practical sequential extraction approach has been applied to two core samples collected from oil zones of Triassic sandstones in Junggar Basin, northwest China. Five bitumen fractions were obtained from each sample using this approach. These fractions are free oil components in inter granular pores (bitumen 1), adsorbed oil components on grain surfaces and liberated by HCl treatment (bitumen 2), oil-bearing fluid inclusions hosted by grains (bitumen 3), and adsorbed oil components on clay mineral surfaces and liberated by HCl and HCl:HF treatments (bitumens 4 and 5). Striking differences have been observed both in bulk compositions and in aliphatic biomarker distributions (e.g., terpanes and steranes) among the five bitumen fractions. This phenomenon is ascribed to the indigenous compositional variations and differential maturation behaviors between adsorbed oil components in a network of polar compounds (resins and asphaltenes) and free oil components in even a same oil charge, in addition to fractional adsorption effects and compositional changes of the oil charges in reservoir rocks during filling process. The molecular compositions and homogenization temperatures of oil-bearing fluid inclusions in these two samples indicate that trapping of these types of inclusions apparently ceased in sample A, while continued in sample B after the initial oil charge, suggesting that the relative content of polar components in the initial oil charge compared to the later oil charges plays a dominant role controlling the trapping of oil-bearing fluid inclusions in an oil saturated zone. Sequential extraction studies are important and useful for reservoir geochemistry, especially in the cases where only limited samples of oil and reservoir rocks are available, and/or where compositional heterogeneity of free oils has disappeared in a reservoir [Karlsen, D.A., Nedkvitne, T., Larter, S.R., Bjørlykke, K., 1993. Hydrocarbon composition of authigenic inclusions: application to elucidation of petroleum reservoir filling history. Geochim. Cosmochim. Acta 57, 3641–3659].

Magnetic signatures produced by fluid flow in porous sediments

Laboratory experiments have demonstrated that a magnetic field is created during the displacement of water by oil in a porous medium. This magnetic field is interpreted to be generated by the electrokinetic effect. The results of the experiments are up-scaled to permit modelling of the electrokinetic-magnetic field generated by a producing oil field. Predicted maximum magnetic anomalies (measured at the Earth’s surface) near oil wells, where the oil-water contact moves vertically at rates between 1 to 5 m/yr (conventional production rates), are in the vicinity of 1 nT or less. However, in the situation where producing wells have unstable pressure regimes, vertical flow rates can exceed 100 m/yr for short periods; maximum magnetic anomalies in the vicinity of 150 nT are predicted under such conditions. Accepting the interpretation that the electrokinetic-magnetic field is produced by randomly changing current loops in the partially oil-saturated zone (transition-zone) of the reservoir, the observed magnetic field is expected to exhibit time-transient behaviour. It is proposed that such a technique could be used to monitor changes to the pressure regime in producing petroleum reservoirs.

Geochemical comparison of oil-bearing fluid inclusions and produced oil from the Toro sandstone, Papua New Guinea

A detailed study was carried out to compare the geochemistry of the crude oil in the Lower Cretaceous Toro sandstone reservoir in the Iagifu-7X well with oil trapped in fluid inclusions in this sandstone in the Iagifu-7X and P'nyang-2X wells in the Papuan Fold Belt. The drill stem test (DST) oils and the oils trapped in fluid inclusions show different source- and maturity-dependent geochemical parameters. Biomarkers suggest that the DST oils at Iagifu-7X were derived from clay-rich, mixed marine/terrestrial source rocks deposited under oxic conditions, probably Middle to Late Jurassic mudstones. The fluid inclusion oils were derived from a less terrestrially-influenced marine source rock deposited under less oxic conditions. The fluid inclusion oils contain 1,2,7-trimethylnaphthalene and oleanane biomarkers indicative of angiosperm input and a Cretaceous or younger source rock. These oils are more mature (calculated reflectance [ R c] = 1.02%) than the reservoired oil at Iagifu-7X ( R c = 0.84%) and condensate at P'nyang-2X ( R c = 0.84%). Source and thermal maturity parameters for all three fluid inclusion samples are similar, suggesting that they were derived from similar source rock facies. Furthermore, samples with predominantly blue vs. white fluorescing oil inclusions have no discernible geochemical maturity difference, suggesting that the use of fluorescence colours as a qualitative guide to the maturity of the trapped oil is not valid in this case. Fluid inclusion oils were trapped prior to charge of the reservoir with oil at the Iagifu-7X and gas condensate at the P'nyang-2X wells. The fluid inclusion oils therefore represent an early oil charge from a deeply buried, probably Cretaceous source rock, which started migrating into the Toro sandstone during the Miocene. At Iagifu this early oil was probably diluted by a larger volume of Jurassic oil generated at the end of the Miocene. The absence of fluid inclusions with compositions like the currently reservoired oil is interpreted to be due to oil charging an already oil-saturated zone, when diagenesis is likely to have been inhibited. At the P'nyang well, the transition from oil (as represented by the oil inclusions) to gas condensate was most likely caused by gas displacement.

Diagenesis of an ‘overmature’ gas reservoir: the Spiro sand of the Arkoma Basin, USA

The Spiro sand is a laterally extensive thin sandstone of earliest Atokan (Pennsylvanian) age that forms a major natural gas reservoir in the western Arkoma Basin, Oklahoma. Petrographic analysis revelas a variety of diagenetic alterations, the majority of which occurred during moderate to deep burial. Early diagenetic processes include calcite cementation and the formation of Fe-clay mineral peloids and coatings around quartz framework grains. These clays, which underwent transformation to well-crystallized chamosite [polytype lb(β = 90°C)]. These clays, are particularly abundant in medium-grained channel sandstones, whereas illitic clays are predominant in fine-grained interchannel sandstones. Subsequent to mechanical compaction, saddle ankerite precipitated in the reservoir at temperatures in excess of 70°C. Crude oil collected in favourable structural locations during and after ankeritization. Whereas hydrocarbons apparently halted inorganic diagenesis in oil-saturated zones, cementation continued in the underlying water-saturated zones. As reservoir temperatures increased further, hydrocarbons were cracked and a solid pyrobitumen residue remained in the reservoir. At temperatures exceeding ∼140–150°C, non-syntaxial quartz cement, ferroan calcite and traces of dickite(?) locally reduced the reservoir quality. Local secondary porosity was created by carbonate cement dissolution. This alteration post-dated hydrocarbon emplacement and is probably related to late-stage infiltration of freshwater along ‘leaky’ faults. The study shows that the Spiro sandstone locally retained excellent porosites despite deep burial and thermal conditions that correspond to the zone of incipient very low grade metamorphism.

Predictions of Horizontal Well Performance In a Mature Waterflood, Weyburn Unit, Southeastern Saskatchewan

Abstract The results of a parametric numerical simulation study led to the development of selection and screening criteria which were used to define horizontal well candidates within the Weyburn Unit of southeastern Saskatchewan. The relative impact of several reservoir and wellbore properties on horizontal well productivity was assessed. This study shows that Weyburn horizontal well performance is improved if reservoir permeability is high, void age replacement is maintained, good communication exists between the two main producing zones, and effective wellbore length is maximized. The well spacing, location and position in the more highly oil-saturated zone were also found to contribute to the productivity of a horizontal well. As a result of this and other engineering and geological work, three successful horizontal wells were designed and drilled in the Weyburn Unit in late 1992. These wells have produced over 19,000 m3 of oil in the first three months of production. Many of the findings of the parametric study, such as well orientation, expected watercut and optimum positioning within the pay, were confirmed by this drilling program. Introduction The Weyburn Unit is located approximately 130 km southeast of Regina, Saskatchewan (Figure 1). The field covers approximately 180 km2 and consists of 627 producing wells and 162 water injection wells. Oil is produced from the Midale Beds of the Mississippian Charles Formation which were deposited on a shallow carbonate shelf in the Williston Basin. The reservoir is subdivided into an upper Marly and a lower Vuggy zone (Figure 2). The Weyburn field was discovered in 1955 and was completely delineated by vertical drilling by 1960. In 1964, the field was unitized and a waterflood was implemented using inverted nine spot patterns oriented in the NE-SW direction. Between 1985 and 1992 over 150 vertical infill wells were drilled within the unit resulting in substantial incremental oil recovery. The infill drilling program concentrated on improving the walerflood performance and vertical wells were drilled on both 24 ha and 16 ha spacing's within some areas of the field. To date, only 25.8% of the 178 million stock tank m3 of medium gravity crude oil have been produced. The remaining oil in place represents a significant target for improved recovery schemes such as horizontal drilling. FIGURE 1: Location of Weyburn Unit. (Available in full paper) In 1991, a horizontal drilling program was conducted in the Weyburn Unit. Three wells were drilled in different parts of the unit to evaluate the technical feasibility of applying horizontal drilling technology. With the number of economically attractive vertical infill targets declining, it was concluded that the future development of the unit would be dependent on the successful application of this technology. Although promising, the results of this drilling program fell far short of what had been anticipated with only one well (10Hz-II) producing any appreciable amount of oil. The low overall productivity of these wells and the success of other wells in the area drilled by other operators led to the development of the parametric numerical simulation study, which is the subject of this paper.

Geology-based conditional simulation in the Athabasca oil sands deposit, Alberta, Canada

The Athabasca oil sands deposit, Alberta, Canada, is one of the largest known hydrocarbon accumulations. The efficient exploitation of this deposit, as well as other oil sand accumulations throughout the world, is based onin situ recovery and surface mining methods. Quantitative modeling of deposit heterogeneity provides a valuable engineering tool. In the present study, conditional simulation was used to model oil-saturated zones in part of the Athabasca deposit. This technique generates equiprobable models of thein situ variability of essential deposit attributes that honor the available data and their spatial statistics. The application of the technique is based on the delineation of geologically homogeneous zones within the host McMurray Formation, their statistical validity, and the integration of geological interpretations. The geological framework is developed, and subsequently, high resolution conditionally simulated models of three identified hydrocarbon-bearing zones are generated, in terms of the zone boundaries and the percent weight of oil saturation. These models serve as “what-if” tools for risk assessment and future planning.

The Effects of Oil Emplacement on Diagenetic Processes: Examples from the Fulmar Reservoir Sandstones, Central North Sea: Geologic Note (1)

Sedimentary petrography and petroleum geochemistry studies have been done on Fulmar Formation (Upper Jurassic) cores from Fulmar field, central North Sea. The extent of quartz overgrowths and albitization of K-feldspars is lower in oil-saturated zones compared with water-saturated zones. However, microthermometric studies of aqueous fluid inclusions in quartz overgrowths show similar temperature ranges for both oil- and water-saturated zones (85-125 degrees C), with maximum recorded temperatures close to the current reservoir temperature (about 130 degrees C). This suggests that quartz overgrowth development in the oil-saturated zones continued after oil emplacement, but was retarded compared with development in the water-saturated zones. The quartz cement, therefore, mus have been essentially locally derived by pressure solution. Albitization of K-feldspars is significantly less (about 50%) in the oil-saturated zones compared with albitization in the water-saturated zones. Because albitization of K-feldspars depends on a supply of sodium and removal of potassium, this process is more likely to be terminated by oil emplacement. The observed difference in the albitization has been used to suggest that the Fulmar reservoir probably was filled during the Neogene. This age estimate agrees broadly with timing determined independently by modeling of oil generation in adjacent source basins. The Fulmar sandstones contain little or no kaolinite and show no evidence of substantial leaching of feldspars or carbonates. This is probably because the Fulmar sandstones, being partly turbiditic, offshore sand deposits, were not exposed to meteoric water. Their close proximity to the marginally mature to mature Kimmeridge Clay Formation seems to have little effect in terms of developing secondary porosity, suggesting that the role of organic acids or CO[2] generated in these source rocks is of minor importance.