Top Of Reservoir Research Articles

Fracture study of a horizontal well in a tight reservoir — Kuwait

An integrated fracture study was conducted to evaluate the fracture flow potential of the low permeability Mishref Formation, using electrical open hole logs, borehole images and production data from a horizontal well, and pressure transient analysis from a vertical well. Image logs show at least three stages of intense faulting and fracturing but the reservoir has only a limited fracture flow potential because (i) the early stage of NW/SE faults and fractures were all cemented. (ii) Although NE/SW fractures generated by recent tectonic episodes and very recent NW/SE fault rejuvenation are open and fluid conductive, faulting created fractures only within the brittle layers, which are a few inches thick and dispersed within thick low porosity and ductile units. Faults have wide fractured zones with flow potential only within a 2–5 ft thick brittle layer close to the reservoir top. The development of fracture permeability in a reservoir requires not only deformation and faulting but also the presence of mechanical layers which are prone to fracturing. A high degree of faulting is not a guarantee for a high degree of fracturing. In this particular reservoir, production from fractures is possible only by targeting the brittle fracture prone layer near the reservoir top of the vicinity of faults.

Influence of fault map resolution on pore pressure distribution and secondary hydrocarbon migration; Tune area, North Sea

AbstractPressure and hydrocarbon migration modelling was carried out in the Tune Field area, Viking Graben, offshore Norway. The pressures are considered to be controlled by compartments bounded by mapped faults. Two different interpreted fault maps at the top reservoir level (Brent Group) are used as input to the modelling. First, a low‐resolution fault map is used, with only the large faults interpreted, and next, both large and small faults are included. The simulations show high overpressures generated in the western area, in the deeper part of the Viking Graben, and hydrostatic in the eastern areas. A sharp transition zone results from using the low‐resolution fault map in the simulations. Small N–S striking faults situated in between the wells have to have higher sealing capacity than expected from juxtaposition analysis alone, to be able to match the overpressures measured in well 30/5‐2 and 30/8‐1S in the Tune Field, and well 30/8‐3 east of Tune. The intermediate pressure in the western part is probably related to flow in the deeper parts of the sedimentary column in the compartment, where well 30/8‐3 is situated. The secondary oil migration models show that overpressures have major effects on the migration pathways of hydrocarbons. The level of detail in the fault interpretation is important for simulation results, both for pressure distribution and for hydrocarbon migration.

AVO attribute analysis and seismic reservoir characterization

This article summarizes some basic concepts in AVO processing and the computation of prestack seismic attributes. Seismic modelling forms the basis for understanding the seismic signature. It helps in the prediction of reservoir characteristics away from well control points. Reliable estimation of petrophysical parameters is needed as input for such studies. These petrophysical estimates are an integral part of more advanced reservoir characterization and modelling. First, the AVO principles are described and various prestack attributes are presented. Subsequently, the elastic approach is discussed and finally the benefits of seismic modelling with advantages of multi-disciplinary reservoir studies are demonstrated. The amplitude character of seismic reflections varies with offset, due to changes in the angle of incidence. The commondepth- point (CDP) gather (Fig. 1a) shows the variation for different traces. Figure 1b illustrates the changes in the seismic response when a water-wet brine-filled reservoir is replaced by oil or gas. The synthetics are calculated along a normal incidence and zero offset trajectory. The hydrocarbon saturation is set at 80% (Robinson et al., 2005). Both hydrocarbon cases show brightening of the reflection with respect to the brinefilled scenario. The sands have lower acoustic impedance (AI) than the encasing shales. Not only the top reservoir reflection shows this increased contrast tendency, but the seismic loop directly below it also manifests considerable changes. Figure 2 illustrates a positive gas-sand reflection decreasing with offset, while the negative water-wet reservoir above shows less reflectivity change. The polarity of the data is normal, i.e. an increase in acoustic impedance with depth (or hard kick) corresponds to a peak to the right on the seismic traces. The two highlighted reservoirs are of differing petrophysical character and the encasing geology (compaction/lithology) changes with depth. Although this kind of amplitude variation is evident on the prestack CMP gathers, it has been somewhat ignored in the past by interpreters because they work primarily with the stacked migration data set. Nowadays, special studies are conducted on a routine basis to analyse the behaviour of the ‘amplitude-versus-offset’ (AVO-studies). This type of data contains detailed information on the porefill of reservoirs (e.g. Ostrander 1984; Castagna and Backus 1993; Chiburis et al., 1993; Hilterman 2001; Veeken et al., 2002; Da Silva et al., 2004a). Ultimately it will lead to a more efficient evacuation of hydrocarbons with substantially improved recovery factors (Fig. 3). The amplitude behaviour of the different raypaths also varies according to the porefill and lithology. Water-filled reservoirs often show variations in amplitude with offset that are different from those of hydrocarbon-filled reservoirs. The change in zero-offset reflectivity R0, or intercept, is the most diagnostic feature. The seismic response depends on the encasing geology, porefill, and interference effects. It varies with depth and differs in various parts of the world. Studying the prestack differences in detail can indicate the causes of near- and far-offset amplitude variability (Fig. 4). The seismic signature from a gas sand is different from the brine-filled response when the same reservoir is observed under similar conditions. In such a situation, the encasing geology is probably the same and has little influence on the observed anomalous amplitude behaviour. A distinct change in zero-offset reflectivity is probably the most remarkable phenomenon. Changes in amplitude with offset can occur in hydrocarbon- as well as water-bearing reservoirs; in that case the intercept might contain the vital porefill information. The AVO effect represents a potentially powerful tool to discriminate between water- and hydrocarbon-saturated reservoirs. However, it means going back to the prestack domain. It should be ensured that the data on individual CDP gathers come from a consistent subsurface location. This is generally achieved by a proper migration of the input data set (prestack time migration, Da Silva et al., 2004b). Careful data preconditioning is essential when quantitative interpretation is the ultimate aim (Veeken and Da Silva, 2004).

APPRAISING THE YOLLA FIELD IN THE BASS BASIN—HOW EFFECTIVE DATA COLLECTION, ANALYSIS AND INTEGRATION INCREASED ESTIMATED HYDROCARBON VOLUMES IN PLACE

Between June and October 2004, two development wells (Yolla–3 and –4) were drilled on the Yolla field in Bass Strait by the T/L1 joint venture. The top and intra-Eastern View Coal Measures (EVCM) hydrocarbon-bearing reservoirs in the field were intersected close to prognosis. A previously undiscovered oil-bearing intra-EVCM sand was encountered in Yolla–4 and the upper EVCM gas and oil bearing reservoir section was completed in Yolla–3 and its productivity confirmed.A key objective of the development drilling campaign was to collect detailed geological and engineering data to assist in field development and quantification of the resource. Subsequent interpretation of these data led to a revision of the depositional facies and reservoir parameters and provided new inputs into a complex 3D reservoir model.The new reservoir model resulted in an upward revision in calculated gas in-place volumes for the intra-EVCM gas reservoirs of about 100 bcf (2,832 m3 x106) or 20% of the pre-drill field size to 600 bcf (16,991 m3x106) and a corresponding increase in recoverable reserves estimates. The upper EVCM is now interpreted to hold 16.5 MMstb (2,623,005 kL) of oil-in-place and total gas-in-place including the gas cap and the solution gas in the oil leg of 33 bcf (934.5 m3x106). These volumes add to the gas reserves for the field, and it is expected that the volatile oil leg will contribute to a richer liquids yield when the zone is produced. The new oil pool in the intra-EVCM has been provisionally estimated at 3.2 MMstb (508,704 kL) oil-inplace with associated solution gas of 2.5 bcf (71 m3x106).

Geostopping With Resistivity-Forward Modeling to Prevent Drilling Into The Loss-Circulation Zone of a Prolific Carbonate Reservoir

Summary The field-development plan for a Sarawak Shell Bhd. operated gas field, located in the South China Sea offshore Sarawak, Malaysia, specified drilling of horizontal wells into the Tertiary-Miocene carbonate reservoir. The wells were planned as high-capacity producers with a big-bore, long-casing flow design. The traditional well design dictated that before entering the reservoir a casing had to be installed to stabilize the hole in soft shale. The uncertainty of detecting the formation top resulted in a premature casing commitment of atleast 30 ft true vertical depth (TVD) above the top of the reservoir and the need to use an expandable liner to cover 300 ft of exposed shale above the reservoir. To obviate this problem, the capability of one of the components in the logging-while-drilling (LWD) tool array, specifically the electromagnetic-wave-resistivity (EWR) forward-modeling technique, was used to detect the top of the carbonate formation (i.e., the top of reservoir),immediately before drilling into it. A standard LWD tool is configured to prioritize EWR forward-model response as the carbonate-formation top is approached. This configuration, together with an appropriately designed bottomhole assembly (BHA) and well trajectory, enabled the successful implementation of the plan to stop drilling approximately 1 ft TVD above the carbonate top. At this point, a conventional 9⅝-in. casing string was set at an optimum depth. This eliminated potential well-control problems, costly remedial actions associated with lost circulation, and inferior cementation of the 9⅝-in. casing string. There after, the wells were drilled horizontally in a conventional manner into the carbonate-gas reservoir. This paper compares predrilling EWR forward modeling of the proposed well trajectory with the actual well data while drilling. The predrilling- and post-drilling-modeled data are presented. The cost savings from employing this technique are variable, ranging from substantial—in the event of a well-control situation and attendant high losses—to moderate if the need to set an expandable liner is eliminated. Aminimum of U.S. $1 million per well was saved with this technique.

Calibrated seismic measurements for improved reservoir definition: a UKCS case study

Steve McHugo, John Bacon, Andrew Furber, and Steve Pickering of WesternGeco present a UK North Sea case study to show the benefits of recent advances in marine seismic imaging. In 2003, WesternGeco acquired a new high-resolution seismic survey for Chevron over the Captain field, UK North Sea. The seismic data were acquired using pointreceiver technology and processed using deterministic data-processing techniques. The objective of the new survey was to provide improved seismic imaging of the field, improve confidence in the detailed mapping of known reservoir zones, and identify new targets. The new survey took advantage of significant technological advances made in seismic exploration. These advances included calibrated point-receiver acquisition, streamer steering, high-accuracy acoustic positioning, and recording of near-field source signatures allowing for much more reliable and detailed images of the subsurface. This article focuses on the impact that sampling and near-field source measurements have on the quality of the final dataset. Background Rose (1999) describes some aspects of the reservoir characterization of the Captain oilfield and refers to issues associated with the seismic data used during appraisal and development. The field, in UKCS Block 13/22 (Figure 1) in the Western Moray Firth, produces heavy oil (19 to 21o API) from two Lower Cretaceous deepwater turbidite reservoirs and an Upper Jurassic shallow marine reservoir. The field was discovered in 1977 and was brought into production in 1997 using closely spaced long-reach horizontal wells. Field appraisal was performed using more than 25 vertical delineation wells; these, combined with existing 1990 vintage seismic data, yielded a top reservoir structure map that has been used to land many long-reach high net-togross horizontal development wells. The 1990 seismic survey, however, provided poor overall imaging and depth estimates of the reservoir zones because of weak signal-to-noise ratio and limited resolution at the key target reflectors. This was primarily caused by known geophysical problems associated with the relatively weak seismic reflectivity of the target sands and the complex geology of the overburden. The new seismic survey was charged with overcoming these geophysical problems.

Chloride Transport in Layered Soil Systems with Hydraulic Trap Effect

The natural and engineered hydraulic trap systems in sanitary-engineered solid waste landfills were investigated using three layer one dimensional laboratory models. The models consisted of a top reservoir containing a sodium chloride source solution, a compacted upper silt layer as a primary liner, a coarse sand layer as a secondary leachate collection system or a hydraulic control layer, a compacted lower silt layer as a secondary liner, and a bottom water reservoir as a groundwater aquifer. In the first test, the natural hydraulic trap system (upward flow through the lower silt layer) was modeled. In this case, the contaminant transport mechanisms through the upper silt layer were downward advection and diffusion, and through the lower silt layer, diffusion was downward and advection was upward. The results showed that the implementation of the natural hydraulic control system could effectively reduce chloride transport to the bottom reservoir. In the second test, the natural and engineering hydraulic trap systems were simulated (upward flow from the bottom reservoir to the upper reservoir). In the third test, the engineered hydraulic trap system (downward flow through the upper silt layer and upward flow through the lower silt layer) was modeled. The results showed that the natural and engineered hydraulic trap systems have an important effect in reducing chloride migration toward the underlying aquifer. In all experiments the chloride concentrations in the silt and coarse sand layers and top and bottom reservoirs were measured and the observed concentrations were compared with concentrations calculated by a theoretical model. A good agreement was obtained between the observed and theoretical data confirming the acceptable accuracy of the experimental methodologies, observations, and the theoretical model.

Overburden distortions—implications for seismic AVO analysis and time-lapse seismic

A 3D finite difference (FD) modelling study is used to investigate the effects of various overburden distortions on seismic data. Two types of distortions are considered: shallow diffractions randomly distributed within a 400 m thick layer and shallow lenses. We find that the presence of overburden diffractors leads to considerable local amplitude variation with offset. However, smoothing of the AVO curves reduces the risk of misinterpretation of AVO data. For shallow lenses in the overburden, we find strong impact on the AVO behaviour at top reservoir level, and that these effects (in contrast to random overburden diffractors) are not reduced by simple smoothing of the AVO data. This study suggests that prior to AVO analysis, it is important to map and identify possible overburden distortions, since various types of overburden effects distort the AVO behaviour in different ways.

Fluid-pressure discrimination in anisotropic reservoir rocks — A sensitivity study

We investigate how seismic anisotropy influences our ability to distinguish between various production-related effects from time-lapse seismic data. Based on rock physics models and ultrasonic core measurements, we estimate variations in PP and PS reflectivity at the top reservoir interface for fluid saturation and pore pressure changes. The tested scenarios include isotropic shale, weak anisotropic shale, and highly anisotropic shale layers overlaying either an isotropic reservoir sand layer or a weak anisotropic sand layer. We find that, for transverse isotropic media with a vertical symmetry axis (TIV), the effect of weak anisotropy in the cap rock does not lead to significant errors in, for instance, the simultaneous determination of pore-pressure and fluid-saturation changes. On the other hand, changes in seismic anisotropy within the reservoir rock (caused by, for instance, increased fracturing) might be detectable from time-lapse seismic data. A new method using exact expressions for PP and PS reflectivity, including TIV anisotropy, is used to determine pressure and saturation changes over production time. This method is assumed to be more accurate than previous methods.

Sea-bottom shear-wave velocities and mode conversions

Elastic parameters for shallow marine sediments were obtained from the literature (Hamilton (1976,1979); Hovem et al. (1991); Esteves (1996)) and previously unpublished geotechnical data from offshore Brazil. The Brazilian data showed reasonable agreement with Hamilton's results except in the very shallow (above 10 m) sedimentary section. A second order equation to calculate VS as a function of depth in marine sediments is derived empirically down to a depth of 140 m. Analyses of transmission and reflection coefficients for compressional- and shear-wave energy mode conversion using Zoeppritz equations were performed for both the sea bottom and a typical hydrocarbon reservoir top of Tertiary age. It is concluded that most S-wave reflection data recorded on the ocean floor by OBC is related to upcoming energy converted at an interface at depth and not from a downgoing shear conversion at the ocean floor. It was also concluded that, using elastic assumptions, mode conversion (both P- to S- and S- to P-) of the up going energy is negligible in the shallow (above 160 m) sediments.

Characterization of the Heimdal Sandstones within Alveim, Quads 24 and 25, Norwegian North Sea

The economics of small fields commonly mean that more attention is needed to create robust geological models ahead of development. Full integration of available core, electronic log and seismic data is essential to reduce uncertainty. In this paper we aim to illustrate how an iterative integration between disciplines has helped to evaluate prospects within the Alveim discovery as the field is delineated. Alveim lies in the Norwegian sector of the North Sea, within parts of quadrants 24 and 25. The primary play is the Paleocene Heimdal Sandstones, which lie up-depositional dip from the Heimdal gas field. The first exploration wells, (24/6-2 and 25/4-3), had proved the presence of both gas and oil within the area. However, subtle closures and imaging problems within the reservoir had made it difficult to initially assess the potential volumes of the prospect. Furthermore, the hydrocarbon column varied across the development area, partially in response to the complex topography (loft) developed at top reservoir. High-order fan abandonment surfaces were recognized and utilized to understand the gross architecture of the Heimdal fan. The sedimentology and depositional processes of the uppermost sequence were then analyzed through full core description. The resulting model was then tested against the observations made from the most recent, higher resolution, seismic analysis, and was then integrated into the geological model.

Designer wells to maximize recovery for Otter Field development, Northern North Sea

The 2002 to 2003 Otter Field development drilling campaign utilized a combination of detailed trajectory planning and integrated geosteering techniques. The objective of this work was to maximize oil recovery, with a minimal number of wells, from the complexly faulted Otter structure. To achieve this, subhorizontal production wells were planned to track near top reservoir, through the structural culminations, to connect adjacent fault blocks. Otter is the most northwesterly of the Brent Province fields of the Northern North Sea, located in UK blocks 210/15a and 210/20d, 530 km north of Aberdeen, operated by TOTAL with partners Shell U.K. Exploration and Production, ExxonMobil and Dana. The field was discovered by the Phillips 210/15-2 well in 1977 (then called Wendy) and appraised by Fina well 210/15a-5 in 1997, following 3D seismic acquisition in 1994. The decision to proceed with development was confirmed after the success of appraisal well 210/15a-6 drilled by TotalFina in 2000. The Otter structure is an easterly dipping tilted panel that is divided into four major blocks and several minor blocks by a network of subsidiary faults. The reservoir is the Middle Jurassic Brent Group, with the uppermost Tarbert Formation shallow marine sandstones comprising the main producing target. The oil source rock is the Late Jurassic Kimmeridge Clay, present in the off-structure areas, though locally absent over the Otter Field area. Top seal is provided by the Mid- to Late Jurassic Heather Shales. The Otter oil is a medium gravity crude (36.5° API) with a GOR of 79m 3 /m 3 (443 scf/bbl), in a normally pressured reservoir at a crestal depth of 1970m subsea. Otter well planning was conducted using a 3D geocellular model based on interpretation of both conventional and acoustic impedance inversion seismic datasets. Apilot study, prior to development drilling, included geochemical and petrophysical reservoir unit definition and the forward modelling of LWD log response in sub-horizontal wells. The results of these studies were used to aid geosteering, incorporating real time chemostratigraphy and LWD data at the wellsite. In addition, borehole resistivity images while drilling were used to assist in structural interpretation in real time and thus to guide the well trajectory to maximize the pay section. A key component in using these new technologies was the office-based integration of all the data via web-based monitoring of the operations. Three production wells target the culminations at the extremities of the Otter Field, supported by a downdip water injector, all drilled from a centrally located subsea template. Following the successful drilling of the first production well, 210/215a-T1, production start-up was in October 2002, via subsea tieback to the Eider facility.

Applications of visualization in the Britannia Field, UK North Sea

Britannia is a large gas-condensate field located 140 miles NE of Aberdeen. The introduction of new tools and workflows has enabled the subsurface team on Britannia Field to increase their understanding of a complex turbidite reservoir whilst continually planning and drilling wells. In 2002, reprocessing of the existing 3D seismic data was completed, giving much improved data quality and a number of new data volumes for interpretation. These and further attribute volumes for reservoir prediction have increased the need for 3D visualization and volume interpretation. Revised, field–wide, top and near-base reservoir picks were made in two stages. 3D volume interpretation techniques were first used to rapidly pick events in good data areas. Then difficult areas were picked and final editing completed using sections and random lines (ribbons). These surfaces were used as the framework for a rebuild of the static geological field model. Fault picking and quality control of structural interpretation has been made easier providing a much improved understanding of faulting in the Britannia field. The new tools and techniques have enabled more of the overburden to be interpreted, giving a fuller understanding of the whole geological story. Flexible well planning is a significant advantage, and visualization tools have helped considerably in well design, especially with contingency planning and communication to management and partners. A number of examples are shown. Britannia is a complex heterogenous turbidite reservoir, and visualization techniques allow greater integration of the seismic with geological models. Flattening and visualization of the results help to understand palaeobathymetry and potential sand distribution patterns. Various detailed cross sections, flattened on different events, build up a picture of sand infill history. Use of colour is particularly powerful here: detailed correlations between many wells can also be inspected more effectively. A number of different pieces of software have been used in the visualization process – no interpreter can become expert in all, but in the subsurface team enough expertise can be gained to significantly impact workflows and productivity. Supplementary material: The movies referred to in the article are available at https://doi.org/10.6084/m9.figshare.c.4812942

Use of reservoir simulation for optimizing recovery performance

A three-dimensional finite-difference reservoir simulator, integrated in an EOR expert system, has been used to determine the reservoir management and production strategies to optimize the oil recovery from a carbonate reservoir. The reservoir is a candidate for an EOR process or otherwise subject to abandonment. After screening the reservoir for an appropriate EOR process on the basis of its properties, it was determined that miscible carbon-dioxide injection is the most suitable process. The management strategies involved studying different design parameters to maximize the project profitability. The injection techniques that were tested in this study include: (1) water-alternating-gas (WAG), (2) simultaneous water-alternating-gas (SWAG) injection, and (3) gas injection in the bottom of the reservoir with water injection in the reservoir top. All simulation runs were conducted using permeability fields that have been conditioned with core data taken from wells in the field. Specific strategy that was used includes the use of horizontal injectors in conjunction with vertical producers. This well configuration has been shown to yield the best oil recovery compared to other well configurations. Simulation results show that the most economical method to produce this reservoir was to simultaneously inject water at the reservoir top and gas at the reservoir bottom. This production strategy has resulted in better sweep efficiency and therefore high oil recovery and good economics.

4D study of fluid effects on seismic data in the Gullfaks Field, North Sea

AbstractThe use of seismic data as a fluid indicator has been investigated on data from a typical North Sea Field (Gullfaks). Examples of qualitative seismic analysis on one single dataset as well as on repeated datasets are shown, clearly demonstrating the usefulness for reservoir description and reservoir management for this field. Quantitative comparisons between expected and measured changes between water‐ and oil‐saturated reservoir rocks are presented. On a single dataset, we found a seismic amplitude increase of 26% between the water zone and the oil zone for the dipping top reservoir horizon. This value was significantly lower than the expected value based on rock physics and simple two‐layer seismic modelling, which was 80%. The discrepancy is attributed to initial oil saturations of probably less than 100%, the relatively high‐noise level in the seismic data, and interference effects with reflectivity from the oil–water contact. For a horizon between a low‐permeable layer (Ness) and a high‐permeable layer (Etive) we find a good quantitative agreement between the observed amplitude increase on the time lapse seismic data (41%) and the predicted amplitude increase from fluid substitution of well logs (40%). The general observation made in this study is that the seismic amplitudes are in good correspondence with the rock physics theory. Furthermore, the seismic fluid effects are visible in good reservoir sands, while heterogeneous sands with higher clay content show a weaker fluid signal on the seismic data.

Productivity Formulae for Horizontal Wells in a Circular Cylinder Drainage Volume

Abstract By the similar methods in References (1), (2), and (3), this paper presents productivity formulae for horizontal wells with circular cylinder drainage volume, using a uniform line sink model. If top and bottom reservoir boundaries are impermeable, the circular cylinder drainage volume radius has significant effects on the horizontal well flow rate. If the reservoir has a gas cap or bottom water, the effect of the circular cylinder radius on flow rate can be ignored, and, under the same top and bottom boundary conditions, the productivity formulae for a circular cylinder drainage reservoir will reduce to the corresponding formulae for an infinite lateral extent reservoir, respectively. Therefore, for a horizontal well, different productivity formulae should be used under different reservoir boundary conditions. Introduction In References (1) and (2), J. Lu presented productivity formulae for horizontal wells in an ellipsoidal drainage reservoir and an infinite lateral extent reservoir. This paper presents productivity formulae for horizontal wells in steady-state with circular cylinder drainage volume. The significant effects of drainage volume radius and boundary conditions on the flow rate of a horizontal well are also demonstrated. The new formulae in this paper, which are derived from the three-dimensional solution of the Laplace Equation as opposed to two-dimensional or pseudo-three-dimensional solutions used in the literature in References (4) - (7), are more accurate in describing the three-dimensional percolation flow through porous media into horizontal wells. Horizontal Well Model Figure 1 is a schematic of a horizontal well. A horizontal well of length L drains a circular cylinder with height H and radius Re. The following assumptions are made:The reservoir is horizontal, homogeneous, anisotropic, and has constant Kx, Ky, Kz permeabilities, thickness H, and porosity Φ. During production, the horizontal well has a circular cylinder drainage volume with height H and radius Re. The middle point of the horizontal well is the centre of the drainage circle.The reservoir pressure is initially constant. The reservoir has edge water, the pressure remains constant and equal to the initial value at lateral surface of the drainage circular cylinder, and the reservoir is bounded by top and bottom impermeable or constant pressure boundaries.The production occurs through a horizontal well of radius Rw, represented in the model by a uniform line sink located at a distance zw from the lower boundary. The length of the well is L.A single phase fluid, of small and constant compressibility Cf, constant viscosity µ, and formation volume factor B, flows from the reservoir to the well at a constant rate Qw. Fluid properties are independent of pressure.There is no water encroachment and no water/gas coning. Edge water, gas cap, and bottom water are taken as constant pressure boundaries, and multiphase flow effects are ignored. Horizontal Well Productivity The equations for the horizontal well and the equations for top and bottom boundary conditions are the same as those in References (1) and (2).

Early-Time Flow Stage Pressure Drawdown Analysis of Horizontal Wells by Instantaneous Steady-State Successive Displacement Method

Abstract By the similar methods in References (1), (2), and (3), this paper presents productivity formulae for horizontal wells with circular cylinder drainage volume, using a uniform line sink model. If top and bottom reservoir boundaries are impermeable, the circular cylinder drainage volume radius has significant effects on the horizontal well flow rate. If the reservoir has a gas cap or bottom water, the effect of the circular cylinder radius on flow rate can be ignored, and, under the same top and bottom boundary conditions, the productivity formulae for a circular cylinder drainage reservoir will reduce to the corresponding formulae for an infinite lateral extent reservoir, respectively. Therefore, for a horizontal well, different productivity formulae should be used under different reservoir boundary conditions. Introduction In References (1) and (2), J. Lu presented productivity formulae for horizontal wells in an ellipsoidal drainage reservoir and an infinite lateral extent reservoir. This paper presents productivity formulae for horizontal wells in steady-state with circular cylinder drainage volume. The significant effects of drainage volume radius and boundary conditions on the flow rate of a horizontal well are also demonstrated. The new formulae in this paper, which are derived from the three-dimensional solution of the Laplace Equation as opposed to two-dimensional or pseudo-three-dimensional solutions used in the literature in References (4) - (7), are more accurate in describing the three-dimensional percolation flow through porous media into horizontal wells. Horizontal Well Model Figure 1 is a schematic of a horizontal well. A horizontal well of length L drains a circular cylinder with height H and radius Re. The following assumptions are made:The reservoir is horizontal, homogeneous, anisotropic, and has constant Kx, Ky, Kz permeabilities, thickness H, and porosity Φ. During production, the horizontal well has a circular cylinder drainage volume with height H and radius Re. The middle point of the horizontal well is the centre of the drainage circle.The reservoir pressure is initially constant. The reservoir has edge water, the pressure remains constant and equal to the initial value at lateral surface of the drainage circular cylinder, and the reservoir is bounded by top and bottom impermeable or constant pressure boundaries.The production occurs through a horizontal well of radius Rw, represented in the model by a uniform line sink located at a distance zw from the lower boundary. The length of the well is L.A single phase fluid, of small and constant compressibility Cf, constant viscosity µ, and formation volume factor B, flows from the reservoir to the well at a constant rate Qw. Fluid properties are independent of pressure.There is no water encroachment and no water/gas coning. Edge water, gas cap, and bottom water are taken as constant pressure boundaries, and multiphase flow effects are ignored. Horizontal Well Productivity The equations for the horizontal well and the equations for top and bottom boundary conditions are the same as those in References (1) and (2).

Sandstone intrusions: detection and significance for exploration and production

Early recognition of sandstone intrusions is a key factor in maximising exploration and production success of the Paleogene deepwater sandstone reservoirs of the northern North Sea. Discordant sandstone intrusions are readily detected in cores, image logs and high quality seismic data by cross-cutting relations with the encasing shales. Many examples of “ratty” sands seen in borehole logs and “artefacts” or “channel margins” seen in seismic data have later proven to be sandstone intrusions, with significant implications for exploration and production. The effects of sand remobilisation and injection include increased connectivity between reservoir compartments, thief sands caused by brecciation and injection into the seal, and large-scale modifications of reservoir geometry, in particular top reservoir. Detailed case studies from the North Sea Paleogene and pilot studies including various other deepwater clastic successions indicate that sandstone intrusions could prove to be an important factor in the development of some highly prolific deepwater provinces such as the West African Atlantic margin. Early recognition of sandstone intrusions in such areas is important for optimal development planning. It requires that the appropriate borehole and seismic data are acquired, and that sandstone intrusions are incorporated in the interpreter’s mindset.

Double-diffusive transport in laboratory thermohaline staircases

Laboratory experiments were conducted on a double-diffusing fluid stabilized by the faster diffuser (T) and destabilized by the slower diffuser (S), the arrangement that leads to salt fingering. The experiments were conducted in three tanks of depths 2 m, 1 m or 0.3 m, with initial linear profiles of S and T between two reservoirs at fixed or known values, S 0 + ΔS, T 0 + ΔT in the top reservoir, S 0 , To in the bottom reservoir. In the thermohaline staircase regime consisting of an alternating stack of convecting layers and finger layers, the overall fluxes F S and F T are clearly not depth independent. The overall Nusselt number, N S varies inversely with the number n of finger layers plus convecting layers occurring in the experimental fluid. The largest Nusselt number occurs for n = 1. The number n increases with increasing mean vertical gradient, up to a point. If the vertical gradients are large, n is always equal to 1. Internal measurements show that in the Rayleigh number range |R S | ∼ 10 15 and density ratio range R ρ ∼ 1.1 to 1.2, the finger flux F f S ∼ (ΔS/h)R a S R b ρ with a = 0.18 to 0.19 and b = 1.8 to 2.1. The data show dependence of F f S on finger layer thickness h. In the convecting layers, N c S R 0.21 for large enough aspect ratio.

The Ivanhoe, Rob Roy and Hamish Fields, Block 15/21, UK North Sea

Abstract The Ivanhoe, Rob Roy and Hamish Fields lie in the Moray Firth of the UKCS in Block 15/21 and contain undersaturated oil trapped in the prolific Upper Jurassic Piper reservoir in tilted fault block traps. The fields were brought on stream in 1989 and since then the reservoir model has undergone several revisions with changes to the calculated oil in place volumes. The two main areas of uncertainty in the geological model are the position of the faults and the distribution of permeability. Improvements in the quality of the seismic data and the well ties brought about greater confidence in the seismic pick at top reservoir and the placement of the major bounding faults to the fields. The reservoir is generally sand-prone with a high net to gross ratio, porosity and permeability, which suggest that the reservoir would behave in a fairly homogeneous manner to fluid flow. Detailed reservoir description shows that this is not always the case. Improvements to the geological model permit a better understanding of the connection between the injector and producer wells and the degrees of influence from faults and heterogeneities in the reservoir to the fluid flow. Based on the current model the present recoverable reserves are estimated to be 187 MMBBL.