Showing papers on "Petroleum reservoir published in 1997"

Quantitative Fault Seal Prediction

Abstract: Fault seal can arise from reservoir/nonreservoir juxtaposition or by development of fault rock having high entry pressure. The methodology for evaluating these possibilities uses detailed seismic mapping and well analysis. A first-order seal analysis involves identifying reservoir juxtaposition areas over the fault surface by using the mapped horizons and a refined reservoir stratigraphy defined by isochores at the fault surface. The second-order phase of the analysis assesses whether the sand/sand contacts are likely to support a pressure difference. We define two types of lithology-dependent attributes: gouge ratio and smear factor. Gouge ratio is an estimate of the proportion of fine-grained material entrained into the fault gouge from the wall rocks. Smear factor methods (including clay smear potential and shale smear factor) estimate the profile thickness of a shale drawn along the fault zone during faulting. All of these parameters vary over the fault surface, implying that faults cannot simply be designated sealing or nonsealing. An important step in using these parameters is to calibrate them in areas where across-fault pressure differences are explicitly known from wells on both sides of a fault. Our calibration for a number of data sets shows remarkably consistent results, despite their diverse settings (e.g., Brent province, Niger Delta, Columbus basin). For example, a shale gouge ratio of about 20% (volume of shale in the slipped interval) is a typical threshold between minimal across-fault pressure difference and significant seal.

The Role of Burial Diagenesis in Hydrocarbon Destruction and H2S Accumulation, Upper Jurassic Smackover Formation, Black Creek Field, Mississippi

Abstract: Organic-inorganic interactions during burial of the Smackover Formation at Black Creek Field, Mississippi, have resulted in nearly complete destruction of hydrocarbons. The formation has been buried to a depth of 6 km, has experienced temperatures of over 200 degrees C, and presently contains 78% H 2 S, 20% CO 2 , and 2% CH 4 . Three distinct stages of burial diagenesis correspond to three phases of organic matter maturation. Pre-oil window diagenesis was dominated by precipitation of prebitumen calcite cement. Diagenesis in the oil window was characterized by precipitation of saddle dolomite and anhydrite in water-filled layers and by formation of solid bitumen in the oil column. Diagenesis in the gas window was dominated by thermochemical sulfate reduction (TSR) resulting in hydrocarbon destruction, anhydrite dissolution, large amounts of H 2 S, CO 2 , and S generation, and postbitumen calcite cementation. During TSR, anhydrite reacted with H 2 S to produce S , which in turn reacted with CH 4 to generate more H 2 S in a self-reinforcing cycle. The lack of metal cations to stabilize H 2 S as metal sulfides, availability of sufficient sulfate to generate H 2 S, and a closed system to prevent H 2 S from escaping resulted in the continuation of the TSR cycle until nearly all hydrocarbons were consumed. In Mississippi, concentration of H 2 S is nearly zero in Smackover hydrocarbon reservoirs that have experienced temperatures of 120 degrees C for more than 50 m.y., suggesting that TSR is not a kinetic (time-dependent) process. High H 2 S concentrations initiate at temperatures above 140 degrees C and increase with temperature, indicating that TSR is a thermodynamic phenomenon. Reported high H 2 S concentrations at low temperatures (80-120 degrees C) from other locations may be explained by the following processes; (1) migration of H 2 S into these reservoirs, (2) high geothermal gradients or local thermal perturbations in the past, (3) a biochemical origin for the H 2 S, or (4) exposure of these reservoirs to temperatures greater than 150 degrees C and a rapid uplift. In Black Creek Field, burial cementation and pressure solution resulted in total destruction of porosity and permeability in limestone reservoirs, but not in dolomite reservoirs, which still possess up to 20% porosity and 100 md permeability. Secondary porosity was not created as a result of hydrocarbon migration. Abundant CO 2 derived during hydrocarbon destruction resulted in calcite cementation rather than carbonate dissolution. Late, secondary porosity development in carbonates may be related to acids generated by metal sulfide precipitation.

Prudhoe Bay Gas/Oil Relative Permeability

Abstract: Prudhoe Bay is a mixed-wet reservoir where about half the oil recovery is attributable to gravity drainage. Gas/oil relative permeability data show that gravity-drainage recovery efficiency is poorer for more fine-grained sandstone and increases as the grain size increases. Gravity-drainage efficiency also increases with connate-water saturation. Dependence of recovery efficiency on grain size is related to changes in sorting. An effective grain size, defined by inverting the Carman-Kozeny relation, provides a useful parameter for correlating recovery efficiency. This estimate correlates well with visual estimates and direct measurements on disaggregated core. Grain size is also found to be a more effective parameter for correlating trapped gas than porosity, a common alternative. Lithology impacts trapped-gas level with finer-grained, more poorly sorted rock having higher trapped gas. Trapped gas decreases with increasing microporosity. Because little gas is trapped in microporosity, a zero-slope generalization of the Land curve better represents trapped-gas data.

Geochemistry of Oils from the Junggar Basin, Northwest China

Abstract: The Junggar basin of northwestern China is a structural basin containing a thick sequence of Paleozoic-Pleistocene rocks with estimated oil reserves of as much as 5 billion bbl. Analyses of 19 oil samples from nine producing fields and two oil-stained cores in the Junggar basin revealed the presence of at least five genetic oil types. The geochemistry of the oils indicates source organic matter deposited in fresh to brackish lake and marine environments, including coaly organic matter sources. The volumetrically most important oil type discovered to date is produced from Late Carboniferous-Middle Triassic reservoirs in the giant Karamay field and nearby fields located along the northwestern margin of the Junggar basin. Oil produced from the Mahu field, located downdip in a depression east of the Karamay field, is from a different source than Karamay oils. Unique oil types are also produced from an upper Permian reservoir at Jimusar field in the southeastern part of the basin, and from Tertiary (Oligocene) rocks at Dushanzi field and Lower Jurassic rocks at Qigu field, both located along the southern margin of the basin. Previous studies have demonstrated the presence of Upper Permian source rocks, and the possibility of Mesozoic or Tertiary sources has been proposed, but not tested by geochemical analysis, although analyses of some possible Jurassic coal source rocks have been reported. Our findings indicate that several effective source rocks are present in the basin, including local sources of Mesozoic or younger age for oil accumulations along the southern and southeastern margins of the basin. Future exploration or assessment of petroleum potential of the basin can be improved by considering the geological relationships among oil types, possible oil source rocks, and reservoirs.

Pressure Behavior of Laterally Composite Reservoirs

Abstract: This paper presents a new general method for solving the pressure diffusion equation in laterally composite reservoirs, where rock and fluid properties may change laterally as a function of y in the x-y plane. Composite systems can be encountered as a result of many different types of depositional and tectonic processes. For example, meandering point bar reservoirs or reservoirs with edgewater encroachment are examples of such systems. The new solution method presented is based on the reflection-transmission concept of electromagnetics to solve fluid-flow problems in 3D nonhomogeneous reservoirs, where heterogeneity is in only one (y) direction. A general Green`s function for a point source in 3D laterally composite systems is developed by using the reflection-transmission method. The solutions in the Laplace transform domain are then developed from the Green`s function for the pressure behavior of specific composite reservoirs. The solution method can also be applied to many different types of wells, such as vertical, fractured, and horizontal in composite reservoirs. The pressure behavior of a few well-known laterally composite systems are investigated. It is shown that a network of partially communicating faults and fractures in porous medium can be modeled as composite systems. It is also shown that the existingmore » solutions for a partially communicating fault are not valid when the fault permeability is substantially larger than the formation permeability. The derivative plots are presented for selected faulted, fractured, channel, and composite reservoirs as diagnostic tools for well-test interpretation. It is also shown that if the composite system`s permeability varies moderately in the x or y direction, it exhibits a homogeneous system behavior. However, it does not yield the system`s average permeability. Furthermore, the composite systems with distributed low-permeability zones behave as if the system has many two no-flow boundaries.« less

Reservoir geochemistry: a link between reservoir geology and engineering?

Abstract: Geochemistry provides a natural but poorly exploited link between reservoir geology and engineering. The authors summarize some current applications of geochemistry to reservoir description and stress that because of their strong interactions with mineral surfaces and water, nitrogen and oxygen compounds in petroleum may exert an important influence on the PVT properties of petroleum, viscosity and wettability. The distribution of these compounds in reservoirs is heterogeneous on a sub-meter scale and is partly controlled by variations in reservoir quality. The implied variations in petroleum properties and wettability may account for some of the errors in reservoir simulations.

Rock types, depositional history, and diagenetic effects, Ivishak reservoir, Prudhoe Bay field

Abstract: The present-day pore system of the Ivishak reservoir is the result of depositional and postdepositional processes. The pore system is a dual system characterized by intergranular porosity, enhanced by leaching, and intragranular microporosity. The combined interaction of deposition and diagenesis together with burial history has caused porosity, permeability, net pay, and water saturation to be highly variable areally and vertically.

Influence of depositional sand quality and diagenesis on porosity and permeability; examples from Brent Group reservoirs, northern North Sea

Abstract: Multivariate statistical analysis was applied to examine correlations between reservoir quality and petrology in two data sets from the Middle Jurassic Brent Group. One of the data sets is from relatively shallow depth and has been little affected by chemical diagenesis (Statfjord Nord and Ost Fields; 2.3-2.6 km below the sea floor), while the second data set is from a more deeply buried reservoir having an advanced degree of diagenesis (Huldra Field; 3.6-3.9 km). Much of the total variation in porosity and permeability within each data set (0.02 mD to > 7 D in both sets) can be accounted for by laboratory measurements of parameters mainly related to depositional sand quality, including "shaliness" (represented by bulk-rock alumina/silica ratio), early carbonate cement, feldspar co tent, and grain size. Despite major differences in the proportions of different sedimentary facies in the two data sets, they have similar ranges of depositional sand quality and therefore probably had similar reservoir quality early in their burial history. Deeper burial diagenesis at Huldra Field has shifted the average of both porosity and permeability to lower values and produced a bimodal permeability distribution, apparently reflecting preferential preservation of permeability in the cleaner sandstones. On the basis of these examples, we outline an approach for unmixing the diagenetic and lithologic components of variation in regional compilations of sandstone porosity-permeability data. The procedure and its consequences are illustrated using a regional compilation of core data fr m the Brent Group of the northern North Sea.

Riphean Hydrocarbon Reservoirs of the Yurubchen-Tokhom Zone, Lena-Tunguska Province, NE Russia

Abstract: The Siberian Craton covers an area of about 4.5 million sq. km in northern Russia, of which up to 3.5 million sq. km may be prospective for hydrocarbons. The craton was consolidated in the Early Proterozoic, and above the basement granitoids and gneisses is a variable thickness of sedimentary strata ranging in age from Riphean (Middle-Late Proterozoic) to Quaternary. Reservoir rocks are known to occur in the interval between the Middle Riphean and the Upper Cretaceous; those of Riphean age have produced oil commercially since 1973. Geochemical data indicate that the oil within the Riphean reservoir rocks was generated by source rocks of Riphean age. Riphean reservoir rocks include both carbonates and siliciclastics, but commercial volumes of hydrocarbons have only been discovered within the carbonates. Three petroleum-bearing “provinces” or megabasins are located on the Siberian Craton: Lena-Tunguska, Lena-Vilyuyand Yenisey-Anabar. The Yurubchen-Tokhom Zone in Lena-Tunguska Province is potentially the most important oil-producing area in the craton, and comprises a number of distinct fields. Reservoir rocks here consist principally of thick Riphean dolomites. Both the development of reservoir characteristics within these dolomites and the formation of stratigraphic traps are related to an episode of emergence and karstification at the end of the Riphean.

Characterization and prediction of reservoir architecture and petrophysical properties in fluvial channel sandstones, middle magdalena basin, colombia

Abstract: About 1 .600 m of core from two major oil fields, and 600 m of outcrop sections near to one of the fields, integrated with thousands of core, side-wall core and outcrop porosity and permeability measurements show that petrophysical properties and reservoir continuity change consistently with the Accommodation to Sediment Supply (A/S) ratio. Channel sandstones exhibit regular, recurring motifs that are associated with changes in A/S conditions. Manifesting the lowest accommodation conditions are amalgamated channel sandstones, up to 5-m-thick, with intraclast-rich bases capped by up to 1 -m-thick floodplain mudstones. AT higher A/S conditions, slightly amalgamated channel sandstones have lateral accretion surfaces and are capped by a thicker unit of floodplain mudstones. Channel sandstones in the highest A/S conditions are single-storied, possess conspicuous lateral accretion surfaces with thick mud drapes, and have a thick cover of overbank and floodplain deposits. Detailed well log correlations, oil production and pressure data support that the former are more lateral continuous while the I after form laterally discontinuous bodies embedded in floodplain mudstones. Petrophysical properties are closely associated with subtle variations in fades, particularly degree of preservation of original bedforms, and both are stratigraphically sensitive. Petrophysical properties of identical sedimentological fades change regularly as a function of itsstratigraphic position because of variations in the rates of accumulation and degree of preservation of the sediments. In the case of fluvial strata deposited during an increase in A/S, porosity and permeability are highest in trough cross-stratified sandstones immediately above channel scour bases, and decrease upward to the next scour base. Successive channel sandstones within the same stratigraphic sequence and channel sandstones from one sequence to the next have progressively lower porosity and permeability values in an overall increase in the A/S. An inverse trend is observed during a decrease in A/S.

Keys to Increasing Production Via Air Injection in Gulf Coast Light Oil Reservoirs

Abstract: Following the long-term commercial success of air injection as a secondary light oil recovery process in the Williston Basin (documented in SPE 27792, 28733, & 35393), Amoco, with the support of the U S Department of Energy, is piloting the use of air injection for tertiary light oil recovery at West Hackberry Field in Southwestern Louisiana Air injection is ongoing at West Hackberry under the following two operating conditions: (1) In a watered out oil reservoir, air is injected to generate incremental oil recovery through the Double Displacement Process (DDP, SPE 28603) DDP is the gas displacement of a water invaded oil column to recover additional oil through gravity drainage West Hackberry possesses steeply dipping high permeability light oil reservoirs that exhibit water drive recoveries of 50%-60% of the OOIP versus gravity drainage recoveries of 90% of the OOIP Although insufficient air has been injected to see production response, reservoir pressure has increased by 500 psi and air injection is continuing (2) In a low pressure reservoir with a gas cap and a thin oil rim, air is injected into the gas cap to push the oil rim to downstructure wells, to repressure the reservoir, and to gain the improved recovery benefit derived from DDP As of May of 1997, the first two low pressure reservoirs to undergo air injection have increased production by a combined total of 150 BOPD (or 60%) above the normal decline To build upon these results, air injection will be extended to similar reservoirs in the field Key project aspects discussed in detail include: (a) valuable field experience gained from injection and production operations, (b) the use of laboratory tests in the selection process for target reservoirs, (c) the interpretation of laboratory results obtained from the combustion tube and the accelerating rate calorimeter, and (d) the numerical reservoir simulation employed to forecast tertiary oil bank development and movement, recovery profiles, and tie-in experimental and field data

Pyrolytic oil-productivity index method for characterizing reservoir rock

Abstract: Data from the pyrolytic analysis of rock samples obtained from drilling operations in an existing oil field are used to characterize the quality and condition of reservoir rock by comparison of the values of an index for the unknown reservoir rock samples with the value of the index for a known type and quality of petroleum reservoir rock sample, the index being denominated Pyrolytic Oil Productivity Index ("POPI") and defined by the expression: ln(LV+TD+TC)×(TD÷TC)=POPI (I), where the terms of the equation are determined empirically and the resulting POPI values can be used to direct horizontal drilling operations in real time to optimize the position of the drilling bit in the reservoir

Stochastic Simulation of Fracture Density for Permeability Field Estimation

Abstract: One of the most difficult tasks in the characterization of reservoir heterogeneities is the representation of naturally fractured reservoirs. Geocellular models for reservoir simulation often require geological interpretation of the distribution of natural fractures both areally and vertically. The FMI data from horizontal wells provide valuable information about the distribution and orientation of natural fractures. Stochastic approaches can be useful in simulating fracture density derived from the FMI logs that would honor the known data. This paper presents stochastic simulation methods for developing the distribution of fracture density in one of the highly fractured reservoirs in Saudi Arabia. Sequential indicator simulation (SIS) method was used with two different variogram models, namely, the fractal and the spherical correlation models. The resulting fracture density field was useful in generating a 3D fracture permeability field for reservoir simulation by using it as a secondary data set in a permeability co-conditional simulation task reported elsewhere.

Prediction of Sand Production from a Saudi Sandstone Reservoir

Abstract: Sand production is encountered in some Saudi oil fields. Six sand samples produced from different wells in a Saudi oil reservoir were obtained. Sandstone samples obtained from the same reservoir were subjected to uniaxial and triaxial failure tests. The debris produced from the sandstone samples and the six sand samples were characterized for their mineralogy using X-ray diffractometer and grain size distribution using standard sieves. Statistical analyses were employed to check whether a statistical difference between the sand samples produced from oil wells and debris collected from the failed sandstone specimens is significant or not. The critical oil rates of the Saudi oil reservoir were also calculated for different well inclination angles. Results show that, no significant statistical difference between the sand samples and debris exists at a confidence level of 95%. Two obvious failure mechanisms, splitting and shear failure, are responsible for sand production from the studied Saudi oil reservoir. The maximum sand-free production for the studied oil reservoir range from 960 to 4080 barrels per day.

Evidencing Capillary Pressure and Relative Permeability Trends for Reservoir Simulation

Abstract: Reservoir simulation requires a realistic spatial distribution of capillary pressure and relative permeability throughout the reservoir. This study aims at deriving relationships between capillary pressure and relative permeability on one hand and porosity, permeability, depositional environment and structural position on the other hand. This work is illustrated by two sandstone oil reservoirs. Sample permeability ranges from 10 mD to several Darcies. Available data include 1) More than one hundred drainage and imbibition capillary pressure curves. Both gas/water, mercury injection and water/oil data was analysed. 2) More than fifty water/oil relative permeability curves. Both fresh and restored-state, steady and unsteady-state corefloods were analysed. Main conclusions are : 1) Drainage capillary pressure curves and irreducible water saturation are strongly correlated with permeability, whatever the experimental technique used. 2) Irreducible wetting phase saturation is significantly larger for water/oil drainage than for gas/water or mercury injection tests. 3) There is no clear trend between drainage capillary pressure curves and depositional environment. 4) Correlation between water/oil imbibition capillary pressure curve and permeability is very weak, unlike drainage. 5) A significant correlation exists between permeability and end-point water permeability or final recovery. 6) Both end-point water permeability and final recovery are found strongly correlated with the height above the initial water/oil contact, whatever the experimental technique used. This reflects the combined influence of initial water saturation and wettability variations. 7) Reservoir trends are often obscured by use of inappropriate laboratory techniques.

Two‐phase oil migration in compacting sedimentary basins modelled by the finite element method

Abstract: The upstream-weighted finite element method with lumped mass matrix is applied to the modelling of oil migration in compacting sedimentary basins. An implicit formulation is made in Lagrangian co-ordinates of a pressure, saturation and a temperature equation, which is based on immiscible two-phase flow of oil and water. The formulation accounts for the compaction of the sediments, the generation of oil from solid organic material (kerogen), the eventual pore space generated by kerogen breakdown, and the density variations of the fluids which may set up thermal convection. The model is validated by comparison with results from a one-dimensional (1D) fractional flow-based migration model. A 2D case example showing oil expulsion from source rocks, and the filling of a trap is presented. The mass balance of the model is easily checked because all oil in the basin originates from breakdown of kerogen. Compared with other alternatives, the simple upstream-weighted finite element method is suggested as a possible first choice for a numerical method for the modelling of oil migration in compacting sedimentary basins. It easily deals with the complex geometry of a basin, it yields reasonably good results, is simple to implement, and the same implementation applies to all spatial dimensions. © 1997 by John Wiley & Sons, Ltd.

Heterogeneity of Fluvial-Deltaic Reservoirs in the Appalachian Basin: A Case Study from a Lower Mississippian Oil Field in Central West Virginia

Abstract: Since discovery in 1924, Granny Creek field in central West Virginia has experienced several periods of renewed drilling for oil in a fluvial-deltaic sandstone in the Lower Mississippian Price Formation. Depositional and diagenetic features leading to reservoir heterogeneity include highly variable grain size, thin shale and siltstone beds, and zones containing large quantities of calcite, siderite, or quartz cement. Electrofacies defined through cluster analysis of wireline log responses corresponded approximately to facies observed in core. Three-dimensional models of porosity computed from density logs showed that zones of relatively high porosity were discontinuous across the field. The regression of core permeability on core porosity is statistically significant, and differs for each electrofacies. Zones of high permeability estimated from porosity and electrofacies tend to be discontinuous and aligned roughly north-south. Cumulative oil production varies considerably between adjacent wells, and corresponds very poorly with trends in porosity and permeability. Original oil in place, estimated for each well from reservoir thickness, porosity, water saturation, and an assumed value for drainage radius, is highly variable in the southern part of the field, which is characterized by relatively complex interfingering of electrofacies and similar variability in porosity and permeability.

Recognition and development of low-resistivity pay

Abstract: In unfractured reservoirs, low-resistivity pay zones can usually be identified with one or more of the following: laminated reservoir/non-reservoir sequences, formations with multi-modal pore-size characteristics, sediments with anomalously high surface area, and reservoir characteristics that extend beyond the range of applicability of interpretative algorithms, e.g. reservoirs containing very fresh formation waters. In all these cases, dry oil has been produced in the presence of high interpreted water saturations, in many different parts of the world. It is therefore important to have a generalised facility for recognising low-resistivity pay as early as possible in the life of a prospect. A systematic procedure is described for the identification of low-resistivity and low-resistivity-contrast pay zones in primary reservoirs. The approach acknowledges that a reservoir rock is a coupled physicochemical system, the method is generic and robust, it is conceptually simple, and it is structured in a manner that is easy to understand. The scheme is modular and it is arranged hierarchically to reflect maturing data scenarios. Therefore it can be progressively refined during the appraisal and development stages. The essence of the method is the definition and calibration of reliable interpretative procedures through quality-assured reference data from key wells by admitting only validated reservoir characteristics. Examples illustrate how'failure to do this can result in much loss of value. The principal thrust is to facilitate the re-evaluation of other wells within the same reservoir system without the need for additional logging programmes. The proposed interpretation scheme also constitutes a basis for the incorporation of new logging technology when this becomes established. The end-product is a flexible petrophysical interpretation scheme for these complex reservoirs that benefits from cost-effectiveness, portability, a higher degree of exactness and consequently a reduced uncertainty.

Evaluation of Capillary Entrapment within Reservoir Flow Units

Abstract: It is well known that millimeter to meter scale sedimentary heterogeneities can affect the displacement efficiency of immiscible flooding by the process of capillary entrapment. There are, however, few practical methods that adequately assess the importance of field-scale capillary entrapment. As a result, the effects of capillary entrapment in small scale sedimentary heterogeneity (e.g. cross stratification) are generally ignored. In this paper, we aim to take a practical approach towards the evaluation of trapping on the field scale. We characterize the most common sedimentary structure found in sandstone reservoirs, the cross bed, by use of a limited amount of parameters. The extent of trapping in any type of sedimentary structure is quantified as a function of the magnitude and direction of the applied pressure gradient in the reservoir. This approach facilitates the calculation of the cumulative effect of a variety of different sedimentary structures present in the vertical succession of reservoir strata. An important aspect of the physical model is that it permits trapping on laminae-scale, as well as trapping on bed-scale. We evaluate the extent of trapping for three different sedimentary flow units; the braided fluvial, the meandering fluvial, and the shallow marine system. The results show a minimal importance of trapping in the shallow marine system due to a low content of trough cross-stratification and very well sorted, reworked sandstone. In contrast, trapping under realistic operational conditions in fluvial systems can easily reach 10-40% of the non-residual oil (1-S wc -S or ). The influence of capillary entrapment in cross stratified reservoirs must be seriously considered during field evaluation.

Measurement of gas-oil contact angle at reservoir conditions

Abstract: Surface forces between rock and fluid system play a major role in the flow characteristics of fluids in hydrocarbon reservoirs, hence, the recovery of hydrocarbons in such media. In petroleum engineering, these forces are indexed by the interfacial tension (IFT) between different phases, and the contact angle between the reservoir rock and the fluids. The evaluation and alteration of these forces are essentul in planning, management and operation of reservoirs for optimum recovery.

Models of the Kawareu geothermal reservoir

Abstract: There has been extensive numerical modelling of the Kawerau geothermal reservoir. Early work by Grant (1977) considered lumped parameter models and provided estimates of re-charge coefficients for the field. Two large-scale three-dimensional models have been developed. Both of these models treat the reservoir as having at least three distinct permeable zones. A shallow zone (above {approximately}400 in) located above the huka formation, a zone at moderate depth ({approximately}800 in) largely associated with andesetic and rhyolitic volcanics and zone(s) associated with faulting in the greywacke basement. Most production is from rock types with low intrinsic permeability; permeability in production zones is believed to be mostly associated with fracturing. This view is consistent with interference test interpretations. This paper will review the early models and also consider in some detail a recent TOUGH2 model. We also consider the use of an inverse modelling program ITOUGH2, as an aid to parameter determination.

Petroleum geology of the state of washington

Abstract: Washington is a petroleum exploration frontier, but there is no current petroleum production in the State. Several possible petroleum systems may be present, hosted by sedimentary rocks deposited in Eocene strike-slip basins and late Eocene and younger intra-arc, fore-arc, and trench basins. Eight conventional petroleum plays, three coal-bed gas plays, and two continuous-type gas plays are delineated in order to analyze and assess the resource potential. In these plays, the potential for significant petroleum accumulations appears greatest in the Columbia Plateau region of eastern Washington. On a regional scale, the absence of high-quality source rocks is probably the most important factor limiting development of large accumulations, although development of suitable reservoirs and an inability to map trays also limits the potential of some plays.

Transgressive Talang Akar Sands of the Kuang Area, South Sumatra Basin: Origin, Distribution and Implication for Exploration Play Concept

Abstract: Transgressive sands of the Talang Akar Formation are productive reservoirs in the South Sumatra Basin and have contributed more than 75 % of oil production in the basin. Sedimentation commenced by deposition of the Lower Talang Akar Formation at N6 characterized by coarse clastics, (an average porosity of 20 %, with permeability more than 5000 md) within a fluviodeltaic environment. The transgressive phase was continued by deposition of the Upper Talang Akar Formation at N7 which is typified by fine clastics, (porosity of 5 – 15 %, and permeability of 40 – 2400 md), deposited within a shallow marine environment. In the Kuang area, the distribution of productive Talang Akar reservoirs is generally controlled by basement highs, and stratigraphic traps form as onlaps along the flanks of the structural highs. The reservoir quality primarily depends on the rock types of local basement highs. Lower Talang Akar is productive in this area as shown by the BRG-005 well in the Beringin Field, which produces 1400 BOPD. The productivity of Upper Talang Akar in this area is demonstrated by the D-209 well of the Air Serdang Field which produces 3900 BOPD. The elements of a petroleum system consisting of source, reservoir, trap, seal and migration in the Kuang area are very favorable for hydrocarbon accumulations. The change of any elements of the petroleum system will lead to different exploration concepts. This paper discusses proven exploration play concepts involving Talang Akar Formation reservoirs in the Kuang area. Beringin Field is examined as it represents fluvial facies, and Air Serdang Field is examined as it involves shallow marine facies. The application of exploration play concepts of the Kuang area to other areas with similar petroleum systems will determine further exploration strategies in the South Sumatra Basin.

Chapter One – Fracturing of a Wellbore and 2-D Fracture Models

Abstract: Publisher Summary The hydraulic fracturing process has been employed to enhance the production of oil and gas from underground reservoirs for more than forty years. In the process, the frac-fluid is pumped at a high pressure into a selected section of wellbore. This fluid pressure creates a fracture extending into the rock medium, which contains oil or gas. As the fracturing operation is conducted at a great depth, the minimum compressive in-situ stress is in the horizontal direction, the hydraulically induced fracture is a vertical fracture. The dimension and propagation characteristics of a hydraulic fracture are important information in the design of fracturing operations. Knowing the properties of reservoir rock, frac-fluid and the magnitude, and direction of in-situ stress, one seeks an accurate prediction of the dimension of the hydraulically induced fracture for a given pumping rate and time. The hydraulically induced fracture propagates from the wellbore into the reservoir as pumping continues. It is clear that the applied wellbore pressure first balances the reservoir pressure and then overcomes the compressive circumferential hole stress, causing a tensile stress on the hole surface. A fracture is initiated when this surface stress reaches the tensile failure stress of the rock medium.

Pematang-Sihapas Petroleum System of Central Sumatra

Abstract: The Pematang-Sihapas(!) petroleum system of Central Sumatra is one of the most important lacustrine oil systems in Southeast Asia. The Brown Shale Formation (lacustrine) of the Pematang Group has generated ~60 × 109 barrels of oil. Sihapas (Early Miocene) sandstones are the principal reservoirs of this system. Giant fields (e.g., Minas and Duri) having Sihapas (marine sandstone) reservoirs occur principally along the eastern margins of sub-basins. Smaller fields having Pematang (nonmarine sandstone) reservoirs are confined to the deeper troughs. The Pematang Group was deposited in a series of small grabens. It exhibits a tripartite stratal architecture: basal (Lower Red Bed) fluvial/alluvial unit; medial (Brown Shale) lacustrine unit; and upper (Upper Red Bed) fluvial/alluvial unit. The Upper Red Bed unit is the main Pematang reservoir. Source rock attributes of the Brown Shale are highly variable. Pyrolysis yields of samples containing > 1.0 wt.% TOC range up to ~120 mg HC/g rock, with a mean of ~25.3 mg HC/g rock. The oil-proneness of the kerogen also varies. The more oil-prone portions of the unit appear in the upper portion of the stratigraphic unit and in the fully lacustrine facies (i.e., poor source rock development occurred in lake margin, deltaic and fan delta facies). Geochemical differences also exist among the different sub-basins. The Pematang Group is disconformably overlain by the Menggala Formation (basal transgressive unit of Sihapas Group). Menggala strata consist of well-sorted quartzose to subarkosic sandstones having an average porosity of > 20% and an average permeability of 1500 md. Menggala sandstones are the most prolific hydrocarbon reservoirs in Central Sumatra. Many of the oil fields in Central Sumatra are associated with paleohighs, drag folds, and post mid-Miocene inversion. Hydrocarbon generation was initiated during the Miocene and continues currently in some parts of the basin.

Development of an integrated reservoir characterization and simulation model for a heterogeneous carbonate reservoir, Arab-D reservoir, east flank of Ghawar field

Abstract: Three dimensional geocellular and simulation models were developed for an area on the eastern flank of the Ghawar Field in the Arab-D carbonate reservoir that displays anomalous flood front advance and the potential for by-passed oil. Results were achieved through the integration of openhole log data, well performance data, production log data, well test and pressure build up data, core descriptions, 3-D seismic structure, and 3-D seismic influenced permeability distributions. The final products were simulation and geocellular models that were consistent with each other and with all of the available engineering and geologic data. This approach has constrained the resulting models towards a more unique solution that can now be used with greater confidence for reservoir management and the identification of areas of lagging flood front or bypassed oil. This study was built upon a previous study which showed considerable success through innovations in model layer selection, mapping of very high permeability areas, horizontal and vertical permeability distribution, grid size and relative permeability assignments. However, the incorporation of other data sets, particularly newly acquired 3-D seismic, demonstrated that the predicted distribution of by-passed oil is dependent upon an accurate description of structure, faults and related fractures as well as rock porosity and permeability. The fully integrated modeling approach utilized here was recognized as a superior way to develop a useful simulation model. This project was accomplished through a multi-disciplinary team approach. The team varied in size and membership as the project developed through its various phases. This project integrated the work of reservoir engineers, reservoir simulation engineers, petrographers, geologists, geophysicists, petrophysicists, and geocellular modelers.

Cut-off or Separation? A New Approach to Distinguish Reservoir Rock from Non-Reservoir Rock for Reservoir Modeling and Simulation

Abstract: The term 'cut-off' refers to a joint effort by geoscientists and engineers to define a value which discriminates non-reservoir rock (shale) from reservoir rock (sand), and has been used in the petroleum industry for several decades. In many instances a single cut-off is not good enough to define sand requiring the use of additional variable cut-offs. The determination of cut-off(s) is highly dependent on a geoscientist's or engineer's experience. There exists no well-defined method that is built on a sound scientific basis. A systematic method is presented in this paper. The new method separates reservoir rock from non-reservoir rock based on the statistical properties and probability distribution functions derived for the various properties of a reservoir interval. It is common that the histogram of a variable (i.e. porosity) has a mixed interval between reservoir and non-reservoir rocks. No matter how a cut-off is defined on the histogram, there will always be a number of values that are incorrectly classified. As a result, we have seen errors in hydrocarbon volume calculation which have been in the range of 5 to 30 %. Unlike the typical application of cut-offs, the proposed method identifies a boundary (no or little mixing) between the two rock populations and then separates them based on this boundary. Correct boundary identification, by analyzing all available variables collected from well logs, is the key to success. When there is no clear boundary, integration of engineering data (i.e. relative permeability and capillary pressure) with the well logs helps to identify possible boundaries or cut-offs. A field study demonstrates the principle of the new method and the improved results includes more than 80 wells. The method is easy to understand and to apply in practice.