Showing papers on "Petroleum reservoir published in 1999"

Decrease in natural marine hydrocarbon seepage near Coal Oil Point, California, associated with offshore oil production

Abstract: Prolific natural hydrocarbon seepage occurs offshore of Coal Oil Point in the Santa Barbara Channel, California. Within the water column above submarine vents, plumes of hydrocarbon gas bubbles act as acoustic scattering targets. Using 3.5 kHz sonar data, seep distribution offshore of Coal Oil Point was mapped for August 1996, July 1995, and July 1973. Comparison of the seep distributions over time reveals more than 50% decrease in the areal extent of seepage, accompanied by declines in seep emission volume, in a 13 km 2 area above a producing oil reservoir. Declines in reservoir pressure and depletion of seep hydrocarbon sources associated with oil production are the mechanisms inferred to explain the declines in seep area and emission volume.

Integrated 3-D Reservoir Modeling Based on 3-D Seismic: The Tertiary Malampaya and Camago Buildups, Offshore Palawan, Philippines

Abstract: Three-dimensional (3-D) seismic interpretation and drilling results indicate complex sedimentary geometries of the Malampaya and Camago build ups (offshore Palawan, Philippines) with localized progradation due to unidirectional offbank transport alternating with vertical aggradation. Successive reduction of size during buildup growth and backstepping of the protected landward margin in response to transgression ultimately appear to have triggered the demise of carbonate production and platform drowning. The shallow-water platform top sediments repeatedly show signs of subaerial exposure before reflooding. A modeling functionality was developed to allow development of multiple-scenario 3-D reservoir models in an exploration or appraisal stage. The model enables merging of seismic-scale observations based on 3-D volume and horizon analyses with subseismic scale information from well data; however, inherent noise within the seismic data introduced by the complex buildup morphology has resulted in inconsistent attribute distribution and fault dimming. These difficulties are compounded by erratic velocity distribution within the limestone, nonhyperbolic move out, and a narrow relatively low-frequency spectrum, all of which prevent the use of the 3-D seismic volume as hard data but rather allow its use as a soft constraint for guiding the geological interpretation and ultimately the modeling process. Seismic data quality in such complex morphologic settings and scarcity of well data hamper greatly the use of geostatistically driven modeling approaches; therefore, a new functionality was developed within Shell's proprietary integrated 3-D modeling suite (GEOCAP), which allows deterministic model reservoirs using seismic horizon and volume interpretation, sequence- and cyclo-stratigraphic architecture, and the concept of reservoir rock type. Seismic velocity in clean carbonate formations is predominantly a function of porosity distribution. To assess time-to-depth conversion uncertainty, the reservoir rock type based models were first produced in the time domain. Only after differential 3-D depth conversion of these models could the scenarios be reconstructed in the depth domain. The depth models subsequently were used to derive permeability and saturation 3-D distortions, and thus hydrocarbon volumes for each deterministic scenario. The models were then used for simulation purposes.

Stress-dependent permeability: Characterization and modeling

Abstract: During the production lifecycle of a reservoir, absolute permeability at any given location may change in response to an increase in the net effective stress and a concomitant decrease in the value of in-situ permeability. This paper focuses stress dependent permeability in unconsolidated, high porosity sand reservoirs (offshore turbidites) and consolidated reservoirs (tight gas sands). Specifically we address: i) fundamental controls on stress dependent permeability, as identified through analysis of core samples, ii) rock-based log modeling of stress dependent permeability in cored and noncored wells, and iii) implications for production based on data from reservoir simulation. This work reveals a fundamental difference between the stress dependent permeability behavior of unconsolidated and consolidated sand reservoirs. In unconsolidated sand reservoirs, the greatest permeability reduction with stress occurs in the sands with the highest values of porosity and permeability. In cemented sandstone reservoirs, the opposite is the case: most of the reduction in permeability occurs in sandstones with the lowest values of porosity and permeability. This difference in behavior between unconsolidated and consolidated reservoir sands is controlled by pore geometry. We present a practical, rapid and cost efficient methodology to improve evaluation and enhance the productivity and management of stress-dependent reservoirs. The method is based fundamentally on the identification of Rock Types (intervals of rock with unique pore geometry). Thin section evaluation, together with integrated nuclear magnetic resonance and SEM-based image analysis of core material is used to quantitatively identify various Rock Types. Rock Type data is integrated with measurements of permeability at various levels of stress. Results demonstrate that, within a particular field, some Rock Types lose 90% of original permeability as a function of increasing stress. Rock Types are then identified using routine suites of wireline logs, allowing for field-wide determination of the net footage and distribution of each Rock Type in all wells and the foot-by-foot calculation of permeability at any value of net effective stress. Based on geological input, the reservoirs are divided into flow units (hydrodynamically continuous layers) and grid blocks for simulation. Several cases are presented of a conceptual, single well model of an overpressured, tight gas sandstone reservoir that include stress dependent permeability. Results of simulation analyses for varying conditions of reservoir stress demonstrate the importance of stress dependent permeability in more accurate forecasting of reserves and predicting optimum well bore producing conditions.

The Perdido Fold Belt, Northwestern Deep Gulf of Mexico, Part 2: Seismic Stratigraphy and Petroleum Systems

Abstract: Analysis of 12,000 km of two-dimensional multifold seismic data shows a thick succession of Mesozoic and Cenozoic deep-water strata in the Perdido fold belt, northwestern deep Gulf of Mexico. These strata differ in seismic facies, areal distribution, and reservoir/petroleum potential. Mesozoic strata are interpreted as dominantly fine-grained carbonates and show minor thickness changes. Cenozoic strata are largely mud-dominated siliciclastic turbidite deposits and vary considerably in thickness across the fold belt. These changes reflect the shifting position of Cenozoic marginal-marine depocenters. Mesozoic reservoir potential consists of fractured Upper Jurassic and Cretaceous deep-water carbonates. Cenozoic reservoir potential consists of siliciclastic deep-water turbidites. Portions of the Paleocene to lower Eocene strata are sand-prone and are the downdip equivalents of the lower and upper Wilcox shallow-marine depocenters. These strata are all incorporated within the folds. Lower to middle Oligocene strata coincide with the main growth phase of the fold belt. Potentially sand-prone middle Oligocene to lower Miocene strata are the downdip equivalents of the Vicksburg (early Oligocene), Frio (Oligocene), and Oakville (early Miocene) shallow-water depocenters. These strata form potential stratigraphic traps against the folds. Mesozoic source potential was modeled assuming Oxfordian, Tithonian, Barremian, and Turonian source beds. One-dimensional thermal maturation modeling showed these sources reached peak oil generation between 51 and 39 Ma, 39 and 8 Ma, 32 and 2 Ma, and 26 and 8 Ma, respectively. Cenozoic source potential was modeled using an Eocene source. Modeling showed this source reached only early oil generation in the basinward half of the fold belt. Thermal maturation was reached by source beds at different times in different locations due to changes in burial depth, amount of structural uplift, and underlying thickness of autochthonous salt. All of these factors indicate that seal and reservoir carry significant risk, but that the potential exists for large petroleum accumulations.

Effects of groundwater flow on mineral diagenesis, with emphasis on carbonate aquifers

Abstract: This article provides a critical synopsis of the effects of groundwater flow on mineral diagenesis. Emphasis is placed on those aspects and processes that change porosity and permeability in carbonate aquifers, because they are of particular importance to human societies as sources of supplies of water for human consumption (drinking, irrigation) and of crude oil and natural gas. Diagenetic settings in carbonates as well as clastics are generally ill defined. This paper proposes a new comprehensive classification of diagenetic settings into near-surface, shallow-, intermediate-, and deep-burial diagenetic settings; hydrocarbon-contaminated plumes; and fractures. These settings are defined on the basis of mineralogy, petroleum, hydrogeochemistry, and hydrogeology. This classification is applicable to all sedimentary basins. Diagenesis is governed by various intrinsic and extrinsic factors that include thermodynamic and kinetic constraints, as well as microstructural factors that may override the others. These factors govern diagenetic processes, such as dissolution, compaction, recrystallization, replacement, and sulfate–hydrocarbon redox-reactions. Processes such as cementation, dissolution, and dolomitization require significant flow of groundwater driven by an externally imposed hydraulic gradient. Other processes, such as stylolitization and thermochemical sulfate reduction, commonly take place without significant groundwater flow in hydrologically nearly or completely stagnant systems that are geochemically "closed." Two major effects of groundwater flow on mineral diagenesis are enhancement and reduction of porosity and permeability, although groundwater flow can also leave these rock properties essentially unchanged. In extreme cases, an aquifer or hydrocarbon reservoir rock can have highly enhanced porosity and permeability due to extensive mineral dissolution, or it can be plugged up due to extensive mineral precipitation.

Hydrocarbon recovery methods by creating high-permeability webs

Abstract: A gravity-drainage hydrocarbon recovery method is provided to produce oil and gas from subterranean formations. A substantially horizontal high-permeability web is created at the bottom portion of an oil reservoir. The web is connected to a production well. The high-permeability web is fabricated by conventional drilling, high-pressure water jet drilling, and high-power microwave fracturing. Primary oil recovery will benefit from this configuration in terms of improved volumetric sweep efficiency, delayed gas break through, increased oil production rate and overall oil recovery. This method is also used with secondary oil recovery for which a gas is injected into the upper portion of a reservoir. Oil is produced from the bottom portion of the reservoir. If economically warranted, high-permeability web is also implemented to the injection well. The method for this invention is also used in conjunction with any horizontal and vertical well arrangement methods, enhanced oil recovery methods, and methods used for oil field conformance improvement.

Correlation between rock fabrics and physical properties of carbonate reservoir rocks

Abstract: Three carbonate core samples from an oil and gas reservoir of the NW German basin were chosen to study the correlation between rock fabrics and physical properties of reservoir rocks. Detailed fabric analyses and texture investigations were carried out as well as laboratory measurements of different physical properties, e.g. density, porosity, permeability, electrical conductivity, seismic compressional and shear wave velocities. Although the three core samples come from a similar depositional facies, they show great differences in the occurrence and three-dimensional distribution of the rock fabric elements. These heterogeneities are the result of various diagenetic and tectonic processes. For the correlation between the rock fabrics and the physical properties four main rock fabric types have to be considered: (a) major constituents, e.g. fossils, ooides, peloides and crystals; (b) pore space with different pore types; (c) fractures; and (d) stylolites. The results of the correlation clearly show that the values and anisotropies of the petrophysical properties are fairly related to the observed fabric elements, with their different arrangements, spatial distributions and preferred orientations. These results also provide a fundamental understanding of the petrophysical responses, such as seismics, to the different geological features (e.g. fractures) and their dynamic changes with pressure, which can be converted to different depths. The knowledge gained from such correlations may lead to an improved interpretation of geophysical data for hydrocarbon exploration and production and therefore to an advanced reservoir characterization.

Stress-sensitive reservoirs

Abstract: Changes in reservoir fluids during production (fluid expansion, dissolution of gas, among others) have long been recognized, but reservoir strata themselves, except for compaction-drive reservoirs, typically have been considered to be static systems. However, a growing number of increasingly sophisticated measurements have demonstrated that some variations in reservoir deliverability are related to interactions between changing fluid pressures, reservoir stresses, and natural-fracture permeability during production and/or injection.

Magnetotelluric survey for exploration of a volcanic‐rock reservoir in the Yurihara oil and gas field, Japan*

Abstract: The Yurihara oil and gas field is located on the southern edge of Akita Prefecture, northeastern Japan. In this area, drilling, surface geological surveys and many seismic surveys have been used to investigate the geological structure. Wells drilled into the Nishikurosawa Basalt Group (NBG) of Miocene age found oil and gas reservoirs at depths of 1.5-2km. Oil and gas are now being produced commercially and further exploration is required in the surrounding areas. However, since the neighbouring areas are covered with young volcanic products from the Chokai volcano, and have a rough topography, the subsurface distribution of the NBG must be investigated using other methods in addition to seismic reflection. According to the well data, the resistivity of the NBG is comparatively higher than that of the overlying sedimentary formations, and therefore the magnetotelluric (MT) method is expected to be useful for the estimation of the distribution of the NBG. An MT survey was conducted along three survey lines in this area. Each line trended east-west, perpendicular to the regional geological strike, and was composed of about 25 measurement sites. Induction vectors evaluated from the magnetic field show that this area has a two-dimensional structure. The evaluated resistivity sections are in agreement with the log data. In conclusion, we were able to detect resistive layers (the NBG) below conductive layers. The results indicate that the NBG becomes gradually less resistive from north to south. In the centre of the northern line, an uplifted resistive area is interpreted as corresponding to the reservoir. By comparison with a seismic section, we prove the effectiveness of the integration of seismic and MT surveys for the investigation of the morphology and internal structure of the NBG. On other survey lines, the resistive uplifted zones are interpreted as possible prospective areas.

Factors Affecting Sand Production from Unconsolidated Sandstone Saudi Oil and Gas Reservoir

Abstract: In this work a physical model has been constructed to simulate sand production from oil and gas reservoirs. The model can accommodate unconsolidated as well as consolidated sandstone cores. The experiments were designed to investigate the effect of confining pressure, flow rate, and the displacing fluid viscosity on sand production mechanism in unconsolidated sandstone formations. Saline water (3.5% NaCl by weight), light (35° API) and heavy (27° API) crude oils were used as displacing fluids in the tests. The main goal of this study was to examine if controlling of the production rate alone can solve the problem of sand production in a Saudi oil reservoir. The oil reservoir is situated in an unconsolidated sandstone formation. A produced sand sample was obtained from this reservoir. Tests were conducted on sand packs having a similar granulomere distribution to that of the reservoir. The experimental results showed that, the magnitude of sand production from the tested porous medium is strongly affected by both flow rate and confining pressure. Sand production decreases with increasing confining pressure and/or decreasing flow rate. Only very fine particles of the porous medium are produced at high confining pressures. When water, or low viscosity crude oil are saturating the porous medium, sand production problem can be managed by controlling the flow rate. In case of saturating the porous medium by heavy crude oil, sand production mechanism becomes different and therefore, controlling only the flow rate cannot stop sand production. Hence, alternative sand control measures must be applied to control sand production in heavy crude oil reservoirs such as down hole emulsification, gravel packing, screen liners, or down hole consolidation.

Stress–strain analysis in productive gas/oil reservoirs

Abstract: A numerical study of the stress–strain distribution in a thin disc-shaped reservoir embedded in a poro-elastic half-space and subject to a unit pore pressure decline is presented. The results are then compared with those of a geometrically equivalent porous cylindrical body which is either free to or prevented from expanding laterally (oedometric analogy). The analysis is based on the linear theory of poro-elasticity solved with the aid of the finite element method. The strength source is provided by the pressure gradient generated in a small region surrounding the gas/oil field where pore pressure dissipates. The influence of the burial depth c is also investigated. The results show that the reservoir rock undergoes a vertical compaction δ which is independent of c and very close to the compaction of the equivalent confined cylinder. The confinement factor is also similar. The horizontal displacement is, however, much larger. Its maximum value occurs at the boundary of the field and is of the same order of magnitude as δ. In addition, at the outer reservoir margin shear stresses develop which are totally missing in both the free and the constrained cylinders. It is shown that the vertical displacements of reservoir top and bottom, as well as the radial ones, are sensitive to c, especially in shallow formations. Finally, the largest shear stress is found to be related to the magnitude of the pressure gradient, i.e. to the radial size of the neighbouring volume where pore pressure vanishes. Copyright © 1999 John Wiley & Sons, Ltd.

Solan, Strathmore and the back basin play, West of Shetland

Abstract: Hydrocarbon migration from the Faeroe–Shetland Basin source kitchen into the Mesozoic back basins that flank its southern margin is prevented by basement highs such as the Rona Ridge. The back basins have long been considered non-prospective due to a perceived lack of source rock and insufficient burial to generate commercial hydrocarbons. The Triassic Strathmore discovery made in 1990, followed by the Upper Jurassic Solan discovery the following year, have demonstrated the prospectivity of the East Solan Basin and similar back basins along the same trend. The two discoveries typify the potential plays in this area, which consist of tilted Palaeozoic and pre-Upper Jurassic structural traps, and syn- to post-Upper Jurassic pinch-out plays against the surrounding structural highs. Strathmore, which straddles UK Blocks 204/30a and 205/26a, consists of dipping Triassic sandstones truncated beneath a broad structural nose mapped at Base Late Jurassic level. The truncated Triassic, which is over 10000 ft thick down-dip, consists entirely of sandstone, but only the lowest, quartz-rich, 550 ft thick Otter Bank Sandstone approaches reservoir quality. The overlying Foula Sandstone has a similar grain size and depositional setting, but its immature detrital mineralogy has resulted in early compactional porosity loss, making the unit an effective top seal to the Otter Bank Sandstone reservoir. Overlying the eastern portion of the Strathmore accumulation in Block 205/26a is the oil-bearing basin floor Solan Sandstone, which sits within the Kimmeridge Clay Formation (KCF), thickening and dipping northeastward into the East Solan Basin. To the southwest the Solan Sandstone forms a stratigraphic trap, onlapping and pinching-out against an intrabasinal high created by the Judd Transfer Zone, which separates the East Solan Basin from the South and West Solan basins. The oil in both the Triassic and Late Jurassic accumulations was generated in the East Solan Basin from the KCF. Both accumulations have similar oil–water contacts, but may be partially isolated in terms of aquifer support. In addition, both share a heterogeneous oil column, which becomes heavier and richer in asphaltene with depth, possibly reflecting two hydrocarbon charges. At present, the 23 × 10 6 BBL oil reserve size (78 × 10 6 BBL STOIIP) of the Solan accumulation is deemed insufficient to justify stand-alone development. Strathmore contains over 200 × 10 6 BBL STOIIP, but the low reserves, estimated at approximately 36 × 10 6 BBL oil, are a function of low matrix permeabilities in all but a few reservoir layers. Only if fracture production can be established will the field be capable of commercial development. Exploration for potential Solan analogues requires the presence of sufficient Late Jurassic section to be confident that the thickening is due to Solan Sandstone presence. Identifying Strathmore analogues is less straightforward. The reservoir is regionally extensive, but is difficult to define seismically without biostratigraphical control (rare in the Triassic) or nearby penetrations of the Otter Bank Sandstone, which are few and far between. Despite the East Solan Basin discoveries proving the play concept, the volumes of hydrocarbons generated by the back basins still remain one of the limiting factors.

Ghaba salt basin province and Fahud salt basin province, Oman; geological overview and total petroleum systems

Abstract: Three Total Petroleum Systems each consisting of one assessment unit have been identified in the Ghaba and Fahud Salt Basin Provinces of north-central Oman One Total Petroleum System and corresponding assessment unit, the North Oman Huqf/'Q'-Haushi(!) Total Petroleum System (201401) and GhabaMakarem Combined Structural Assessment Unit (20140101), were identified for the Ghaba Salt Basin Province (2014) In the Fahud Salt Basin Province, however, two overlapping Total Petroleum Systems (TPS) were recognized: 1) the North Oman Huqf Shu'aiba(!) TPS (201601); Fahud-Huqf Combined Structural Assessment Unit (20160101), and 2) the Middle Cretaceous Natih(!) TPS (201602); Natih-Fiqa Structural/Stratigraphic Assessment Unit (20160201) The boundary for each Total Petroleum System also defines the boundary of the corresponding assessment unit and includes all trap styles and hydrocarbon producing reservoirs within the petroleum system In both the Ghaba and Fahud Salt Basin Provinces, hydrocarbons were generated from several deeply-buried source rocks within the Infracambrian Huqf Supergroup One general 'North Oman Huqf type oil is dominant in the Fahud Salt Basin Oils in the Ghaba Salt Basin are linked to at least two distinct Huqf source-rock units based on oil geochemistry: a general North Oman Huqf-type oil source and a more dominant 'questionable unidentifiedsource' or 'Q'-type Huqf oil source These two Huqf-sourced oils are commonly found as admixtures in reservoirs throughout northcentral Oman Hydrocarbons generated from Huqf sources are produced from a variety of reservoir types and ages ranging from Precambrian to Cretaceous in both the Ghaba and Fahud Salt Basin Provinces Clastic reservoirs of the Gharif and Al Khlata Formations, Haushi Group (M Carboniferous to L Permian), dominate oil production in the Ghaba Salt Basin Province and form the basis for the Huqf/'Q' Haushi(!) TPS In contrast, the Lower Cretaceous Shu'aiba and Middle Cretaceous Natih limestones account for most of the production in the Fahud Salt Basin with about 50 percent of the basin's production from porous, fractured Shu'aiba limestones in Yibal field, thus the name North Oman Huqf -Shu'aiba(!) TPS Deep gas is produced mainly from Middle Cambrian to Lower Ordovician clastic reservoirs of the Haima Supergroup Traps in nearly all hydrocarbon accumulations of these petroleum systems are mainly structural and were formed by one or more mechanisms These trap-forming mechanisms were mainly periodic halokinesis of the thick Cambrian Ara Salt and consequent folding and faulting from basin loading, rifting, or other major tectonic events, particularly those events forming the Oman Mountains and associated foreland-basin system during the Late Cretaceous and Late Tertiary Many of the future new-field targets will likely be low-relief, subtle structures, as many of the large structures have been drilled Oman's recent interest and commitments to liquid natural gas export make deep gas a primary objective in the two North Oman Huqf petroleum systems New-field exploration of deep gas and exploring deeper targets for gas in existing fields will likely identify a significant gas resource in the next thirty years Moreover, salt-diapir flank traps in these two North Oman Huqf petroleum systems and salt basin provinces have gone essentially untested and will likely be targeted in the near-future The Middle Cretaceous Natih(!) TPS is a small efficient system of the Fahud Salt Basin Natih source rocks are only mature in the Late Cretaceous/Tertiary foredeep and production is primarily from Natih reservoirs; minor production from the Shu'aiba limestone is documented along fault-dip structures Most traps are structural and are related to development of the foreland basin and formation of the Oman Mountains Future targets of the Natih TPS will be less obvious than those of Fahud and Natih fields and likely include smaller structural closures along the northern flank of the foreland bulge and traps above salt domes with late Tertiary movement Frontier exploration is predicted to be mainly in stratigraphic traps within Natih buildups and in unproven turbidite and other marine elastics of the Fiqa Formation Petroleum Systems and Geologic Overview of Ghaba and Fahud Salt Basin Provinces Pollastro

Estimating Pore Pressure and Permeability in Massively Stacked Lenticular Reservoirs Using Diagnostic Fracture-Injection Tests

Abstract: How does one determine pore pressure and permeability in a well containing 26 reservoirs when pressure-buildup tests are impractical and wireline formation testers have proven ineffective Operating companies often face this challenge when completing massively stacked lenticular tight-gas sands. During early field development, the pore-pressure differences between sands may be inconsequential to the completion and production of the well; however, as infill wells are drilled, individual sands may be pressure depleted and jeopardize the completion/stimulation of the remaining sands at original pore pressure. Tight-gas reservoirs in the San Juan, Uinta, Piceance, Greater Green River, and Wind River basins contain fields with individual sands demonstrating pore-pressure depletion. Since many of the massively stacked lenticular sands are stimulated using limited-entry fracture designs, one or two depleted sands can effectively divert an entire fracture treatment from sands at or near original pore pressure. This paper describes how multiple diagnostic fracture injection tests are used to (1) identify pressure-dependent leakoff, e.g., from fissure opening (natural fractures); (2) identify pressure-depleted sands; (3) estimate gas permeability; and (4) optimize multiple sand completions. The analysis methods include G-Function analysis for pressure-dependent leakoff, pore-pressure estimates calculated from the stress-depletion relationship of the reservoir rock, and permeability estimates from conventional before-closure leakoff analysis and the modified Mayerhofer method.

Estimation of critical gas saturation during pressure depletion in virgin and waterflooded reservoirs

Abstract: An important issue in petroleum engineering is the prediction of gas production during reservoir depletion--either following conventional waterflooding operations or in the early stages of hydrocarbon production. The estimation of critical gas saturation for use in corresponding simulation studies is clearly a primary concern. To this end, a 3D, three-phase numerical pore-scale simulator has been developed that can be used to estimate critical gas saturations over a range of different length scales and for a wide range of fluid and rock properties. The model incorporates a great deal of the known physics observed in associated laboratory micromodel experiments, including embryonic nucleation, supersaturation effects, multiphase diffusion, bubble growth/migration/fragmentation, oil shrinkage, and three-phase spreading coefficients. The precise pore-scale mechanisms governing gas evolution have been found to be far more subtle than earlier models would suggest because of the large variation of gas/oil interfacial tension (IFT) with pressure. This has a profound effect upon the migration of gas structures during depletion. In models pertaining to reservoir rock, the process of gas migration is consequently much slower than predictions from more simplistic models would imply. This is the first time that bubble fragmentation and IFT variations have been included in a model of gas evolution at the pore-scale and the implications for production forecasting are expected to be significant. In addition, novel scaling groups have been derived for a number of different facies under both virgin and waterflooded conditions. One future application of these groups would be to scale S gc values obtained from high rate depressurization experiments to the low rate conditions more characteristic of field operations.

Equi-pressure geosteering

Abstract: A method for determining a desirable depth for drilling a horizontal well within an oil reservoir includes the steps of deploying a plurality of data sensors at discrete depths in a subsurface formation penetrated by a wellbore, gathering formation pressure data for the discrete depths using the data sensors, and determining the depth of a reservoir using the gathered formation pressure data. The depth within the reservoir may be determined by identifying from the gathered formation pressure data at least one depth whose corresponding formation pressure is suggestive of a reservoir. Once such a depth is identified, the wellbore itself or a lateral drainhole depending from the wellbore may be steered into the reservoir by maintaining the trajectory of the wellbore or drainhole at a substantially constant distance from a fluid contact within the reservoir.

Comparison of Permeability from NMR and Production Analysis in Carbonate Reservoirs

Abstract: Several issues come to mind in the pursuit of log-derived permeability. Two of them, often referred to in recent publications, are the accuracy of the parameter and the representative of this permeability. Permeability from nuclear magnetic resonance (NMR) logs is often compared to core, wireline formation tester mobility, drillstem test and production data. The variation in vertical and lateral extent of these different measurements can give valuable insight into reservoir behavior. Average matrix permeability can be estimated from wireline NMR measurements while the other methods can more accurately evaluate the directional reservoir permeability as it varies with heterogeneities such as vugs, fractures, maximum horizontal stress and stylolites. Determining matrix permeability in carbonates from NMR data has been considered more difficult than in typical sandstone reservoirs. Recent developments in NMR carbonate analysis have provided insight as to how the permeability estimation from NMR logs can be improved. A method will be presented that overcomes some of the limitations of using NMR permeability in carbonates and will be compared with conventional NMR permeability estimation, core, wireline formation tester and drillstem test analysis in three Middle East carbonate reservoirs.

Reservoir production method

Abstract: A method of producing an oil reservoir having a gas cap and an oil column. A first injection fluid, such as water, is introduced into the reservoir at the gas-oil contact and gas and oil are simultaneously produced from the gas cap and oil column, respectively. A second injection fluid, such as water, may be introduced at a point in or below the oil column.

Characterization of Reservoir Lithologies within Subunconformity Pools: Pekisko Formation, Medicine River Field, Alberta, Canada

Abstract: The Pekisko Formation in western Canada is a third-order sequence comprised of an open-marine grainstone through restricted carbonate mudstone succession. Truncation of the Pekisko along an unconformity edge prior to the Jurassic and several periods of incision from Early Jurassic-Early Cretaceous have formed an intricately sculptured subcrop belt. In the Medicine River field, oil is trapped in discrete pools close to the unconformity edge. Reservoir facies comprise three lithologies. Medium-crystalline dolostone with intercrystalline and vuggy porosity forms the reservoir in an elongate dolostone body that has replaced grainstone. Fine-crystalline dolostone is facies selective within a lime-mudstone unit in which the common reservoir rock is bioturbated dolomudstone with intercrystalline porosity. Grainstones have secondary porosity formed though leaching of microcrystalline calcite allochems and intergranular cements. Reservoir quality is assessed from consideration of orthogonal permeability values (Kmax = maximum horizontal permeability, K90 =horizontal permeability at 90° to the maximum, and Kv = vertical permeability) obtained from conventional whole-core analyses. Sedimentary lamination primarily affects the Kv, and the presence of fine-grained lamination dictates that Kv 3K90 and Kv > K90. From this relationship, the fracture density in all three lithologies appears to be similar. Low and variable porosity and permeability values in grainstones indicate that the fracture system is poorly connected to the matrix. Despite leaching and fracturing at the unconformity edge, reservoir distribution closely follows patterns of facies that were susceptible to dolomitization. Future exploration potential lies in fine-crystalline dolostone bodies that may form stratigraphic traps downdip from the unconformity edge.

Chemical Composition of Gases as a Geochemical Tracer of Natural Gas Migration

Abstract: The chemical compositions of gases released from sedimentary rocks by acidolysis, canned head-space gases of rocks and commercial natural gases, which were collected from different areas of various oil/gas bearing basins in China, were analyzed. Combined with natural gas generation and geological evolution of Ordos basin, Tarim basin, Ying-Qun basin and Huanghua depression, the chemical composition change resulted from natural gas migration was discussed in this paper. As a result of the obvious fractionation in the chemical composition during gas migration through porous sedimentary rock, the evidence that the molecular of methane will preferentially migrate to heavier gaseous hydrocarbons and normal butane to isobutane was recognized . 1. acidolysis gases released from sendimentary rock The compositional ratios of C 1/C 2+ and C 1/C total of the gases released from sedimentary rocks by acidolysis, which were collected from 3 080～3 560 m section of well Chenchuan-1 in Ordos basin, decrease with increasing of the buried depth ( as shown in Fig. 1 ). The organic matter in this section is from condensate to over-mature and three gas producing layers are found in brown sandstone with TOC values less than 0.3%. However, above two ratios resulted from thermal gas generation from organic matter should tend to increase with depth corresponding to its thermal maturation. This suggests that the molecular methane preferentially transfer to heavier gaseous hydrocarbons during gas migration. 2. canned head-space gases The methane concentration and heavier gaseous hydrocarbons concentration of canned head-space gases from reservoir rocks are far greater than those from source rocks (Fig. 2a), which are collected from 3 600～4 438 m section of well Chenchuan-1. And the ratio of C 1/(C 2+C 3) is much bigger in the reservoir rock than source rock and becomes bigger and bigger with the depth (Fig. 2b). C 1 and C 2+ concentration in the source rock of 6th to 10th section of Majiagou Ⅴ group are obviously larger than those of Majiagou Ⅰ group to Ⅳ group and the C 1/(C 2+C 3) ratio becomes bigger with buried depth, indicating that natural gases generated in the 6th to 10th section of Majiagou Ⅴ group is migrated and trapped in the reservoir. 3. commercial natural gases The natural gases with the same origin identified by δ 13 C 1 andδ 13 C 2 values are trapped in different reservoirs, which are distributed in Donghetan reservoir of Tarim basin, Dongfang1-1 and Luodong15-1 reservoirs of Ying-Qun basin and Qikou sag of Huanghua depression. Their chemically compositional change of C 1/C 2+ , C 1/C total and C total gaseous hydrocarbons /C total non-hydrocarbons in the vertical also reveals that the molecular of methane preferentially migrate to heavier gaseous hydrocarbons and hydrocarbons to non-hydrocarbons. As a result of migrational fractionation, the natural gas with much more methane than heavier hydrocarbons is trapped in relatively shallow reservoirs.

Analysis of Overpressured Reservoirs with A New Material Balance Method

Abstract: This work presents application of a new material balance method to detect aquifer influence and calculate water influx and original gas in place for four over-pressured reservoirs. Calculation of water influx needs to satisfy a set of three equations as opposed to the existing method of one equation of unit slope. In each application, the presence of aquifer influence was identified first, and then material balance was used to determine original gas in place and water influx. The overpressure effect was handled by integrating rock compressibility over operating reservoir pressure. Compositional effects were modeled with R v (volatile oil/gas ratio) by matching PVT data using Walsh-Towler algorithm or an Equation-of-State. This new method is internally consistent, which avoids potential pitfalls of existing methods. Comparison with other methods in analyzing overpressure reservoirs shows this new method is more robust and comprehensive.

Conversion of air permeability to liquid permeabilities extracts huge source of information for reservoir studies

Abstract: Permeability data form great part of data input in all of simulation studies. The importance of permeability data increases as the production life of oil fields becomes to later stages. However, the industry has a huge source ofonly air permeability measurements and a little number of liquid permeability values due to the relatively high cost of special core analysis. The present study suggests a correlation to convert air permeability into oil and brine permeabilities for Nubia C reservoir. Data of more than one hundred samples were gathered from 16 wells that are producing fore fields: October, Ramadan, East Tanka and Sidki. The data of other three fields: Hilal, Gebel El-Ziet, and Ras-Budran were used for to confirm the validity of the derived equations for oil and brine permeabilities. The comparison with the commonly used tables of Amoco conversion shows a higher accuracy and more consistent results over a wide range of permeability values. The conversion of air permeability to liquid permeabilities forms a cost-effective method for coring. The new correlation also introduces more feasible estimation in case of loose and poorly consolidated sands, or in case of the unavailability or invalidity of old cores to carry out oil and brine permeabilities. Further, the conversion formula offers the possibility to make a better use of the large amount of old air permeability data obtained through routine core analysis for the various further uses in geological modeling, reservoir simulation studies, reservoir surveillance/monitoring and production technological work.

Ghaba salt basin province and Fahud salt basin province, Oman; geological overview and total petroleum systems

Abstract: Three Total Petroleum Systems each consisting of one assessment unit have been identified in the Ghaba and Fahud Salt Basin Provinces of north-central Oman. One Total Petroleum System and corresponding assessment unit, the North Oman Huqf/'Q'-Haushi(!) Total Petroleum System (201401) and GhabaMakarem Combined Structural Assessment Unit (20140101), were identified for the Ghaba Salt Basin Province (2014). In the Fahud Salt Basin Province, however, two overlapping Total Petroleum Systems (TPS) were recognized: 1) the North Oman Huqf Shu'aiba(!) TPS (201601); Fahud-Huqf Combined Structural Assessment Unit (20160101), and 2) the Middle Cretaceous Natih(!) TPS (201602); Natih-Fiqa Structural/Stratigraphic Assessment Unit (20160201). The boundary for each Total Petroleum System also defines the boundary of the corresponding assessment unit and includes all trap styles and hydrocarbon producing reservoirs within the petroleum system. In both the Ghaba and Fahud Salt Basin Provinces, hydrocarbons were generated from several deeply-buried source rocks within the Infracambrian Huqf Supergroup. One general 'North Oman Huqf type oil is dominant in the Fahud Salt Basin. Oils in the Ghaba Salt Basin are linked to at least two distinct Huqf source-rock units based on oil geochemistry: a general North Oman Huqf-type oil source and a more dominant 'questionable unidentifiedsource' or 'Q'-type Huqf oil source. These two Huqf-sourced oils are commonly found as admixtures in reservoirs throughout northcentral Oman. Hydrocarbons generated from Huqf sources are produced from a variety of reservoir types and ages ranging from Precambrian to Cretaceous in both the Ghaba and Fahud Salt Basin Provinces. Clastic reservoirs of the Gharif and Al Khlata Formations, Haushi Group (M. Carboniferous to L. Permian), dominate oil production in the Ghaba Salt Basin Province and form the basis for the Huqf/'Q' Haushi(!) TPS. In contrast, the Lower Cretaceous Shu'aiba and Middle Cretaceous Natih limestones account for most of the production in the Fahud Salt Basin with about 50 percent of the basin's production from porous, fractured Shu'aiba limestones in Yibal field, thus the name North Oman Huqf -Shu'aiba(!) TPS. Deep gas is produced mainly from Middle Cambrian to Lower Ordovician clastic reservoirs of the Haima Supergroup. Traps in nearly all hydrocarbon accumulations of these petroleum systems are mainly structural and were formed by one or more mechanisms. These trap-forming mechanisms were mainly periodic halokinesis of the thick Cambrian Ara Salt and consequent folding and faulting from basin loading, rifting, or other major tectonic events, particularly those events forming the Oman Mountains and associated foreland-basin system during the Late Cretaceous and Late Tertiary. Many of the future new-field targets will likely be low-relief, subtle structures, as many of the large structures have been drilled. Oman's recent interest and commitments to liquid natural gas export make deep gas a primary objective in the two North Oman Huqf petroleum systems. New-field exploration of deep gas and exploring deeper targets for gas in existing fields will likely identify a significant gas resource in the next thirty years. Moreover, salt-diapir flank traps in these two North Oman Huqf petroleum systems and salt basin provinces have gone essentially untested and will likely be targeted in the near-future. The Middle Cretaceous Natih(!) TPS is a small efficient system of the Fahud Salt Basin. Natih source rocks are only mature in the Late Cretaceous/Tertiary foredeep and production is primarily from Natih reservoirs; minor production from the Shu'aiba limestone is documented along fault-dip structures. Most traps are structural and are related to development of the foreland basin and formation of the Oman Mountains. Future targets of the Natih TPS will be less obvious than those of Fahud and Natih fields and likely include smaller structural closures along the northern flank of the foreland bulge and traps above salt domes with late Tertiary movement. Frontier exploration is predicted to be mainly in stratigraphic traps within Natih buildups and in unproven turbidite and other marine elastics of the Fiqa Formation. Petroleum Systems and Geologic Overview of Ghaba and Fahud Salt Basin Provinces Pollastro

Preliminary Hydrocarbon Source Rock Assessment of the Paleozoic and Mesozoic Formations of the Western Black Sea Region of Turkey

Abstract: Source rock maturity and potential of Paleozoic and Mesozoic formations in the Eregli, Zonguldak, Bartin, Ulus, and Eflani subregions of the western Black Sea region (WBSR), have been investigated by rock-eval pyrolysis, reflected-light microscopy, and palynofacies analyses. The % Ro values of dispersed organic matter of the Paleozoic formations primarily range from 0.72 to 1.8%, but values as high as 2.6% occur locally in the Silurian Findikli Formation in the Eregli subregion. The % Ro values of Namurian-Westphalian coal seams in the K20/H well drilled in the Zonguldak subregion range from 0.87 to 1.52%, with increasing depth consistent with sedimentary depth of burial. Most Cretaceous age samples have reflectance values ranging from 0.44 to 1.6% Ro that indicates they are marginally mature to mature with respect to the oil window. Rock-eval pyrolysis demonstrates that the Paleozoic formations have limited oil-generation potential (HI values {le} 200 mg HC/g C{sub org}), but good gas potential (TOC values up to 3%). Cretaceous formations have better petroleum source rock characteristics, but they too are primarily gas prone. Variations in the source rock maturity probably reflect variable burial histories in different localities of the WBSR.

Reservoir Characterization Of Fractured Reservoirs In Western Canada

Abstract: The author has worked on a number of fractured reservoirs in Western Canada, which show common characteristics. Production performance, pressure transient responses and stimulation results are discussed. A reservoir characterization is presented which is consistent with observed production performance, pressure transient responses, production logging results, core analysis and well stimulation. A key component is structural geological style. This description has been applied to a number of different reservoir situations. It has application to stimulation design, predicting reservoir performance, numerical simulation and pressure transient analysis. An example is also highlighted from a gas condensate reservoir. FIGURE 1: Core porosity vs. core permeability. Alberta Central Foothills Carbonate Reservoir all samples. Foothills reservoir. The Brazeau River Elkton/Shunda is located about 50 km to the east of the preceding example. The pool is located on a subcrop edge and is also a type of fractured reservoir. However the fracturing is derived from a different source—Karst development. Core permeability vs. core porosity from this field is shown in Figure 3. It is immediately obvious that the data does not resemble the “shotgun blast” or “triangular” appearance of the foothills reservoir. The average permeability and porosity are 56.54 mD and 9.25% (574 points). The Foothills reservoir core averaged 22.392 mD with a porosity of 4.11%. It is interesting to note that at an average porosity of 4.11%, the non foothills core has an average permeability of 0.3 mD to air (at surface conditions). Another reservoir that shows the Foothills type of core permeability vs. core porosity was plotted for a Wabamun D-1 reservoir, as shown in Figure 4. The core data shows a classic triangular distribution of core permeability vs. core porosity. In the author’s opinion this is diagnostic of fracturing derived from structural (Foothills type) deformation. Structural Style Effect Figure 5 shows a cross-section through a Western Canadian sandstone reservoir. As part of an economic evaluation the author plotted well AOF and type curve reservoir interpretation. This diagram shows the basic building block of structural style in Western Canada, which is a thrust fault. Well performance is strongly affected, depending on where in the structure wells are completed: 1. Along the top of the overthrust sheet leading edge, well deliverabilities are very high. Type curves, for this reservoir were typically single porosity radial responses. 2. Underneath the thrust sheet, and adjacent to the shear zone, long slivers of reservoir rock are dragged up or broken off. In this area a number of bi-linear test results were obtained. 3. Further ahead, there are a series of faults, that are of a much smaller scale than the thrust sheet. In this area, type curves indicate systems with concentric permeabilities. 4. Behind the thrust sheet on the “back limb,” well tests indicated hydraulic fractures and mixed medium deliverabilities. One thing that was immediately obvious was that there was good permeability across the front of thrust sheet. 2 Journal of Canadian Petroleum Technology FIGURE 2: Core porosity vs. core permeability. Alberta Central Foothills Carbonate Reservoir fractured samples only. FIGURE 3: Core porosity vs. core porosity. Alberta Central Foothills Brazeau River (Subcrop) reservoir. FIGURE 4: Core porosity vs. core permability. FIGURE 5: Alberta Sandstone Reservoir, thrust sheet.

Screening of oil reservoirs for selecting candidates of polymer injection

Abstract: Polymer flooding has been found to be an excellent method for improving oil recovery from marginal oil reservoirs with intense heterogeneity or high-producing water-oil ratios (WOR). Accurate analysis, however, must be conducted prior to deciding on a polymer flooding operation. Even though the petroleum literature has reported a set of criteria for screening oil reservoirs for polymer flooding and their qualitative analyses, rarely can one find any quantitative analysis outlining the validity of the commonly held views in the petroleum industry. This article presents a quantitative analysis of the performance of an oil reservoir subjected to polymer slug injection. Fluid and rock properties are varied in order to determine the economics of an enhanced oil recovery scheme. The reservoir parameters considered in this analysis are reservoir permeability (230-2300 md), initial water saturation (0.25-0.5), and oil viscosity (25-100 cp). In order to study the role of field operational parameters in determining...