bluuebunny/crossref_metadata_2025 huggingface dataset:
The palingenesy of the Piper oil field, UK North Sea
Authors: Harker S. D.
Published: November 2010

Piper was discovered in 1972 by the 15/17-1A well, located on a 4-way dip closed structure on the northern flank of the Witch Ground Graben. Appraisal drilling through 1973 showed the field to comprise four gently folded, tilted fault blocks with productive reservoirs in Late Jurassic paralic to shallow marine sandstones (Sgiath and Piper formations). Production commenced in 1976 and until the Piper Alpha disaster of 1988, the field had produced 834X10
6
bbl oil out of the then estimated recoverable reserves of 952X10
6
bbl. Redevelopment started by pre-drilling 1 injection and 7 production wells based on 1990 reprocessed 3D seismic, prior to the installation of the Piper Bravo platform in 1993. A study of permeability repartition and sweep efficiency, combining existing and new well data from cores, logs, pressures and fluid distribution, aided the optimization of well locations. In addition, a new 3D seismic survey was acquired in 1992-3. Advantageous fluid redistribution and natural aquifer repressurization of the reservoirs occurred during the 4 1/2 years of production shutdown. By mid-1996, 12 production and 4 injection wells were in operation. Piper Bravo wells redeveloped three of the four fault panels, using half of the number of wells in operation at the time of the Piper Alpha disaster. The production rate has been significantly increased over the projected 1988 decline and a much lower water cut achieved. The ultimate recovery for the Piper field is now estimated at 1014X10
6
bbl oil (-3.4%), an increase of 62X10
6
bbl over the pre-redevelopment figure.
Finding a regular geometry for an irregular reservoir shape for well performance calculations
Authors: Tehrani D. H. , Chen G. , Peden J. M.
Published: November 2010

The shape and geometry of the reservoir play an important role in well pressure performance calculations by analytical methods. Dietz (1965) reported analytical solutions for a variety of regular shape reservoirs. He presented a table of shape factors for different geometries circle, square, triangle etc.) and different locations of the well within the reservoir. However, no solution is available for an irregular geometry or for any shape that is not covered in the Dietz shape factor table. This paper presents a method in which a numerical simulator is used for an irregular shape reservoir to obtain an equivalent regular geometry that produces the same well performance as that of the real irregular reservoir. The well can be slanted or horizontal and can be situated anywhere within the reservoir. To do this an optimization routine is used which minimizes the sum squared deviations between the well block pressures as obtained by the numerical simulators for both shapes. Once the nearest regular shape has been identified, well performance calculations can be carried out using an analytical method selected from those presented by Dietz or by the same authors in their recent papers.
Geological controls on remaining oil in Miocene fluvial and shoreface reservoirs in the Mioceno Norte area, Lake Maracaibo, Venezuela
Authors: Ambrose W. A. , Mendez M. , Akhter M. Saleem , Wang F. P. , Alvarez R.
Published: November 2010

Facies architecture and structure are the primary controls on reservoir geometry, fluid-flow pathways, and distribution of remaining oil in fluvial and shoreface reservoirs of Miocene age in the 46.7 km
2
Mioceno Norte area in northern Lake Maracaibo. This mature field is undergoing depletion and nearing the final stages of primary recovery. Although the area has produced oil since the 1940s, appreciable volumes of oil (commonly 400 to 1200X10
3
STB (stock tank barrels)/20-acre drainage area) remain in multiple, poorly contacted reservoir sandstones at the current 984 ft (300 m) well spacing. Detailed lithofacies maps document the control of sandstone architecture on hydrocarbon distribution and demonstrate that the current well spacing on a grid pattern is too large to recover efficiently the remaining oil. Moreover, the facies architecture influences water-cut patterns and the irregular advancement of inferred oil-water contacts on the western margin of the field. A wide variety of infill wells, recompletions, redrilled wells, horizontal wells, and water-injection wells is proposed. Approximately 80X10
6
STB of remaining oil will be produced by maintaining the current 984 ft (300 m) well spacing. However, an additional 46.5X10
6
STB can be produced with geologically targeted infill wells, recompletions and horizontal wells. In addition, new water-injection wells can appreciably increase oil recovery by enhancing sweep efficiency and providing pressure support.
Relationship between remaining oil saturation after waterflooding and rock/flow properties at laboratory and reservoir scale
Authors: Maldal T. , Jakobsen S. R. , Alvestad J. , Arland K. S.
Published: November 2010

The dependency of waterflood remaining oil saturation (S
or
) on initial water saturation (S
wi
), wettability and flow rate has been studied in the laboratory at core scale. For both water-wet and mixed-wet cores, S
or
was found to be inversely proportional to S
wi
. For mixed-wet cores, S
or
was also found to be inversely proportional to the number of pore volumes injected. In contrast, water-wet cores showed a dependency between S
or
and flow rate, indicating that pore structure plays an important role. The oil saturation development in several waterflooded intervals in the Gullfaks Field has been monitored, mainly by saturation logs, over several years. Oil saturation was found to decrease inversely with time after water breakthrough. Also, an oil saturation distribution with depth, which seems to depend on the balance between capillary and gravitational forces, was found.
Variation of gas-oil-solid contact angle with interfacial tension
Authors: Al-Siyabi Z. , Danesh A. , Tohidi B. , Todd A. C.
Published: November 2010

Contact angle has a major influence on the distribution of multi-phase fluids within petroleum reservoir rocks. However, there is little information on the variation of gas-oil-rock contact angle with pertinent parameters in the literature. In this study, it has been observed that the contact angle is almost constant at high gas-oil interfacial tension (IFT) above a threshold value and declines at a variable rate, depending on the volatility of the mixture, approaching zero at the critical point. The generated data were used to develop a generalized correlation between the contact angle and IFT and other measurable parameters of the system.
Macroscopic description of foam flow through porous media
Authors: Zemskikh V.
Published: November 2010

This paper investigates theoretically the possibility of describing foam flow through porous media based upon the usual equations for two-phase flow of immiscible fluids through porous media. It found a class of solutions which can describe the main features of foam flow during gas mobility reduction (gas-blocking regime). An expression for the "gas mobility reduction factor" has been derived from the current consideration. The analysis of this expression shows that this factor is equal to the ratio (liquid mobility without foam)/(gas mobility without foam) at liquid saturation very close to the irreducible one. A method for calculating the gas mobility reduction factor is proposed.
The significance of vaterite occurrence in tube blocking tests using Na-K-Ca-Cl-HCO
3
-H
2
O brines at 120 degrees C
Authors: Mulshaw Sean , Locardel Beatrice
Published: November 2010

CaCO
3
scaling at 120 degrees C and formation water flow along well tubing during production, is modelled using tube blocking experiments utilizing Na-K-Ca-Cl-HCO
3
-H
2
O brines. All tests produced scale assemblages dominated by aragonite, vaterite (< or =45%) and some calcite. Vaterite is a rare form of CaCO
3
so its occurrence is particularly significant. Vaterite precipitation was initiated by rapid CaCO
3
supersaturation, driven by lower CaCO
3
solubility at 120 degrees C, combined with high relative concentrations of HCO (super -)
3
in the brine (HCO (super -)
3
/Ca = 12). Few accounts of oil field scaling focus on carbonate mineralogy. The formation of mixed-carbonates in this study emphasizes that more attention should be paid to mineralogical characterization of carbonate scale in relation to production conditions, formation water chemistry and inhibitor selection. This could lead to improvements in both scale prediction and inhibitor efficiency.
The prize; what's possible?
Authors: Weber K. J.
Published: November 2010

Recovery factors for comparable reservoirs are often from 10 to 20% higher in the USA than elsewhere. The reason is the relatively low cost of drilling and work-over combined with the high revenue per barrel for the producer in the States. This implies that elsewhere the scope for additional recovery will frequently be of the same order as the noted differences. Another motivation for re-evaluation of older fields is the realization that irreducible oil saturations measured on core plugs in the past were generally much too high. Consequently, the assumed sweep efficiencies were much too high also, resulting in little incentive for infill drilling or recompletion. A number of factors stimulate the re-evaluation of remaining reserves. Reliable through-casing logging makes the poorly swept zones visible. Detailed structural definition is often possible with 3D seismic. New drilling techniques, like short radius horizontal side tracks, allow economic recompletions of old wells.
A sleeping giant awakened; further development of the Seria Field, Brunei Darussalam, after almost 70 years of production
Authors: Watters D. G. , Maskall R. C. , Warrilow I. M. , Liew V.
Published: November 2010

The Seria Field was discovered in 1929. Cumulative oil production reached 164X10
6
m
3
(end 1996), approximately 34% of known in-place volumes. A maximum oil production level of 18 780 m
3
/d in 1956 has since declined to 2800 m
3
/d. Most of the more easily recoverable oil has now been produced. Undeveloped oil is concentrated in economically marginal accumulations for which simple subsurface models are an inadequate basis on which to plan further development activities. Instead, dynamic simulation of detailed computer-generated 3D reservoir models is required to optimize reservoir management and evaluate potential development options. 3D seismic data are used to assess undrilled closures and new exploration plays resulting in the development of new hydrocarbon accumulations. Amplitude analysis combined with GST/RST logging has identified areas of unswept oil within the field. Detailed 3D reservoir geological models integrating sequence stratigraphic concepts with reappraisal of core and wireline data are being built using Unix workstations. The models incorporate the results of advanced petrophysical techniques, such as image analysis and resistivity inversion, to quantify net sand, porosity and saturation, and NMR to provide information on moveable oil and permeability. The model forms the input to advanced reservoir simulators where multiple sensitivities can be tested to determine the optimum placement of new wells. Advances in drilling technology have led to the use of horizontal and multi-lateral wells to give the increased productivity necessary for commercial success of such marginal developments. Concurrent engineering effort has led to the field's facilities being rationalized to improve efficiency and reduce costs and the designing of re-usable well jackets for the shallow offshore part of Seria.
The Gullfaks 4D seismic study
Authors: Landro Martin , Solheim Odd Arve , Hilde Eilert , Ekren Bjorn Olav , Stronen Lars Kristian
Published: November 2010

A time lapse analysis was performed on two 3D seismic datasets (4D seismic) acquired over the northern part of the Gullfaks oilfield in the North Sea. The first survey was acquired in 1985, prior to the production start in 1986, a second survey was acquired in 1995, followed by a third in 1996. The drainage interpretations carried out by means of the repeated seismic datasets are in reasonable agreement with similar interpretations performed the traditional way by reservoir engineers, and have locally resulted in an improved understanding of drainage. The time lapse seismic data are routinely used in well planning projects on Gullfaks. In 1997, two wells were drilled into segments that, based on repeated seismic data, were interpreted to be undrained. Both wells encountered oil-filled reservoirs. Although these wells were not based on time lapse seismic alone, the wells served as a good test of the reservoir management potential associated with the 4D technology. Furthermore, waterfront movements predicted on the basis of time lapse seismic data are confirmed by well observations.
Vibroseismic simulation for rehabilitation of water flooded reservoirs
Authors: Lopuchov G. P.
Published: November 2010

A correlation between oil rates and earthquakes was observed in the 1970s. It resulted in the first attempts to use the energy of seismic waves to mobilize residual oil spread in the reservoir in the form of drops of different sizes, and to rehabilitate depleted oil fields with high water production. Laboratory tests showed that oil displacement can be increased by application of low-frequency vibration. It was also confirmed by field tests (results reported at VI EOR ES, 1991): oil production due to vibroseismic stimulation increased by 30-40%. However, estimations show that such an increase in oil production does not occur with low-frequency vibration. Most probably some unknown phenomena exist which impact on the mechanism of seismic vibration-induced increases in oil production. The object of this study was the development of an analytical model of vibroseismic stimulation to explain the mechanism of residual oil mobilization. Such a model can provide the basis for effective use of vibration stimulation. The model oil-saturated formation consists of blocks of different sizes. Each large block includes several blocks of smaller sizes. Block sizes depend on the geological processes taking place during their formation, while correlation between their sizes does not depend on properties of constituent materials. Core measurements taken in the millimetre range and analysis of photographs of layer distribution in open hole taken in the metric range show that correlation between the large and small blocks occurs over a rather small range and varies between 2.91 and 3.43. Simulation of vibroseismic impact on a formation shows that a process of low-frequency energy transfer from larger blocks to smaller ones, producing high-frequency vibration, takes place. These high-frequency vibrations provide conditions under which capillary forces, retaining oil drops in the porous media, are destroyed, improving conditions for oil mobilization. These results agree with experimental data of noise measurements recorded during pilot commercial tests of vibroseismic action at different oil fields in Russia. Thus the possibility of residual oil mobilization by applying low-frequency vibroseismic stimulation was confirmed both theoretically and in laboratory and field tests. The results received were an essential part of the creation of the technology for vibroseismic stimulation of waterflooded, depleted oil reservoirs.
Simulation of hydraulically fractured wells
Authors: Ding Y. , Chaput E.
Published: November 2010

Fractured wells are frequently encountered in petroleum engineering. They can be hydraulically fractured wells to improve oil production or wells intersecting natural fractures. Due to the presence of the fractures, the flow behaviour and the pressure distribution in the vicinity of the fractured well are complex and the numerical modelling for this kind of well is complicated. There are no efficient numerical methods to simulate these wells, especially for the fractured horizontal or multi-lateral wells. In this paper, we discuss the new techniques for fractured well simulations using the reservoir simulator. A new method, which is based on the calculation of suitable numerical PI at the well blocks and of transmissibilities around the fractured wells according to the steady-state pressure distribution, is proposed for fractured well modelling. This method can provide satisfactory results with coarse grid simulations.
Key characteristics of three-phase oil relative permeability formulations for improved oil recovery predictions
Authors: Balbinski E. F. , Fishlock T. P. , Goodyear S. G. , Jones P. I. R.
Published: November 2010

Significant three-phase regions can occur in a range of reservoir development strategies and oil relative permeability may then critically affect ultimate oil recovery. Unfortunately, three-phase oil relative permeabilities are not generally well characterized. In this paper we focus on theoretical methods of estimating three-phase oil relative permeabilities, as typically applied in reservoir simulation. In the absence of good physical models, we propose applying a mathematical filter to the many existing methods before fitting to measured data. First, the key characteristics of methods for predicting three-phase oil relative permeabilities are discussed, including choice of variables, behaviour at low oil saturations and three-phase residual oil saturations. Second, a numerical comparison of both predicted oil relative permeabilities and predicted incremental oil recoveries for immiscible WAG over waterflood is presented. None of the four most commonly used formulations assessed passed the mathematical filter successfully. Shortcomings were found in both of Stone's commonly used formulations for estimating expected recoveries. A wide range of incremental oil recoveries for immiscible WAG was found from choosing different formulations or different three-phase residual oil saturations. Some recommendations for best practice have been made.
Recognition and evaluation of low-resistivity pay
Authors: Worthington Paul F.
Published: November 2010

A systematic procedure for the petrophysical identification and interpretation of low-resistivity and low-resistivity-contrast pay zones in intergranular reservoirs is founded upon an analysis of case histories for different reservoir types in diverse areas of the world. The approach acknowledges that a reservoir rock is a coupled physico-chemical system. The proposed 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 world-wide illustrate how failure to recognize low-resistivity pay can result in much loss of potential value.

A principal thrust is to facilitate the re-evaluation of other wells within the same reservoir system without the need for excessive acquisition of additional data. However, the proposed interpretation framework does allow the incorporation of new logging technology as this becomes established. The end-product is a flexible petrophysical interpretation scheme for these unconventional reservoirs that benefits from cost-effectiveness, portability, a higher degree of exactness and consequently a much reduced uncertainty.
Closing the gap between theory and practice in seismic interpretation of small-scale faults
Authors: Hesthammer Jonny , Henden Jon Ottar
Published: November 2010

The ability to map small-scale faults from seismic surveys depends upon resolution, noise content and acquisition/processing procedure. In addition, the geoscientist must possess a sound understanding of plausible geometries consistent with analyses of well data. The comparison of two seismic datasets from the Gullveig structure, northern North Sea, demonstrates that the lateral resolution of the data is strongly dependent on the signal-to-noise ratio. By combining a theoretical approach with statistics from well analyses, exemplified by data from the Gullfaks Field, it is possible to enhance our understanding of the limits of fault resolution on 3D seismic data.
Experiments on clay smear formation along faults
Authors: Sperrevik Susanne , Færseth Roald B. , Gabrielsen Roy H.
Published: November 2010

A ring shear apparatus was used to investigate the development of clay smear along faults in sand–clay sequences. Experiments were performed, using six different clay types, different stress conditions (σ
n
=6–500 kPa) and different amounts of clay (4 and 12.5%). The development of clay smear seems to depend on the competence contrast between the clay and the surrounding sand. Clay, when it is less competent than sand, behaves in a ductile manner, resulting in the development of clay smears along the fault. Clay which is more competent than sand behaves in a brittle manner, resulting in the formation of angular fragments. Whether the clay is more or less competent than the sand is dependent on the stress conditions, the initial porosity of the sand and the mechanical properties of the clay. The results suggest that stress conditions allowing the sample to contract will result in the formation of fluid flow barriers, whereas dilation results in the formation of conduits.
Distribution pattern of hydrogen sulphide-bearing gas in the former Soviet Union
Authors: Belenitskaya G. A.
Published: November 2010

H
2
S is an unwelcome accompaniment to natural hydrocarbon gas but, in sufficient volumes, it can provide an economic source of sulphur, termed a ‘gaseous sulphur’ accumulation. Such accumulations are an important component of the sulphur reserves of Russia and other countries. A comparative study of the distribution of economic gaseous sulphur accumulations, together with native sulphur deposits, in the Amu Dar’ya, Volga–Urals, North Caspian and other basins of the former Soviet Union and elsewhere shows that they occur only within large hydrocarbon basins and are restricted to thick and regionally persistent evaporite–carbonate successions. The lithological and geochemical controls and various types of sulphur paragenesis result in a zoned series of accumulations, from gaseous sulphur to sulphur-rich oils to native sulphur, which can be traced from the deep central regions of hydrocarbon-bearing basins with sulphate–evaporite successions towards the shallow basin margins.
Use of 3D digital analogues as templates in reservoir modelling
Authors: Bryant I.a.n. , Carr David , Cirilli Peter , Drinkwater Nicholas , McCormick David , Tilke Peter , Thurmond John
Published: November 2010

Geological analogues may be used to rigorously interpret three-dimensional (3D) subsurface reservoir geometry by combining the capabilities of graphics workstations with digital outcrop data collection. Digital data from sedimentary environments and outcropping geological formations are interpreted in a 3D viewing environment to construct 3D templates of analogues for reservoir bodies. These 3D geometries and associated scaling parameters are then available to build 3D digital hypotheses concerning subsurface reservoir geometries.

Two examples serve to illustrate this approach. Data from a modern fluvial system in the USA are used to construct digital templates. Interpretation of this dataset enables the relationship between 3D external geometries of sedimentary units to be rigorously defined and related to internal sedimentary structures. The location of gas-filled reservoir compartments in the Carboniferous Bend Conglomerate reservoirs of the Boonsville Field in North Texas are then interpreted using such analogue-derived digital templates.
Use of 3D digital analogues as templates in reservoir modelling
Authors: Bryant Ian , Carr David , Cirilli Peter , Drinkwater Nicholas , McCormick David , Tilke Peter , Thurmond John
Published: November 2010

Geological analogues may be used to rigorously interpret three-dimensional (3D) subsurface reservoir geometry by combining the capabilities of graphics workstations with digital outcrop data collection. Digital data from sedimentary environments and outcropping geological formations are interpreted in a 3D viewing environment to construct 3D templates of analogues for reservoir bodies. These 3D geometries and associated scaling parameters are then available to build 3D digital hypotheses concerning subsurface reservoir geometries.

Two examples serve to illustrate this approach. Data from a modern fluvial system in the USA are used to construct digital templates. Interpretation of this dataset enables the relationship between 3D external geometries of sedimentary units to be rigorously defined and related to internal sedimentary structures. The location of gas-filled reservoir compartments in the Carboniferous Bend Conglomerate reservoirs of the Boonsville Field in North Texas are then interpreted using such analogue-derived digital templates.
Neogene wrench reactivation of the Barcoo Sub-basin, northwest Australia: implications for Neogene tectonics of the northern Australian margin
Authors: Keep Myra , Bishop Anna , Longley Ian
Published: November 2010

The Barcoo Sub-basin forms the southern part of the Browse Basin of Australia’s northwestern margin. Miocene reactivation of older Precambrian through Mesozoic-aged structures has resulted in a present-day complex right-lateral wrench zone. The fault system displays restraining and releasing bends separated by areas of almost pure strike-slip displacement, along its 180 km length. Reactivation and inversion varies along the system, with the southern end structurally highest, offsetting beds up to and including the seafloor. The location of restraining and releasing bends controls the occurrence of oil and gas shows in nine wells drilled in the sub-basin, with Neogene inversion causing trap leakage in a number of cases. Right-lateral motion on the Barcoo Fault system, in contrast to a proposed regional-scale left-lateral movement component on the northwestern margin as a whole, implies strong strain partitioning along the margin with regional tectonic control. We propose that the structural domain boundaries may be controlled in part by the location of the continental collision zone between the northernmost limit of Australian continental crust with the southernmost continental fragments of the Eurasian plate, in the vicinity of the island of Sumba.
Sand body geometry, constrained and predicted during a horizontal drilling campaign in a Lower Cretaceous turbidite sand system, Captain Field, UKCS Block 13/22a
Authors: Rose P. T. S. , Manighetti A. A. , Regan K. J. , Smith T.
Published: November 2010

The Captain Field is a large viscous oil accumulation located in the Western Moray Firth, UK Block 13/22a which is being developed by long horizontal wells. The reservoir sand body geometry was defined in the appraisal phase by 20 vertical wells. Seismic attributes were not used because of the poor seismic signal to noise ratio in the reservoir interval. As the development drilling campaign has unfolded, the appraisal sand body geometry model has been significantly refined using a wealth of data from the horizontal wells.

During development drilling it has proved cheap to sidetrack horizontal well sections without a requirement to isolate the abandoned hole. This has resulted in significant extra geological data (e.g. top reservoir penetrations, sand thickness data). Integrating this dataset with top reservoir topography derived from seismic and weak internal reservoir seismic reflectors, the sand body geometry model is significantly improved in undeveloped parts of the field.
Controls on the Lower Cretaceous Punt Sandstone Member, a massive deep-water clastic deposystem, Inner Moray Firth, UK North Sea
Authors: Argent J. D. , Stewart S. A. , Underhill J. R.
Published: November 2010

Interpretation of high-quality seismic data, constrained by exploration wells, provides insights into controls on the stratigraphic architecture and deep-water sedimentary processes that governed deposition of the Lower Cretaceous Punt Sandstone Member in the Inner Moray Firth Basin. We suggest a model of deposition in which sediment provenance from the north and west progressively filled depositional accommodation in proximal depocentres before spilling into more distal areas via linear, confined and incised channel complexes. As well as giving important clues into post-rift depositional processes in the basin, and a well-imaged ancient analogue for the deposition of massive deep-water sands, the seismic and stratigraphic data may also provide important insights into factors governing the poorly imaged Lower Cretaceous sands in neighbouring basins of the North Sea.
Lower Cretaceous turbidites of the Moray Firth: sequence stratigraphical framework and reservoir distribution
Authors: Jeremiah Jason M.
Published: November 2010

Lower Cretaceous depositional systems of the Moray Firth are influenced by eustatic sea-level oscillations which have been dramatically overprinted by two major phases of pulsed tectonism, the Late Cimmerian and Austrian. The biostratigraphical resolution obtained has allowed the timing and differentiation of distinct tectonic/sequence boundaries, some of which are utilized as important seismo-stratigraphic markers. The construction of detailed facies maps for individual sequences has, in parallel, allowed an insight into the tectonic history of the main source areas during the Early Cretaceous.
An Early Cretaceous lithostratigraphic and biostratigraphic framework for the Britannia Field reservoir (Late Barremian–Late Aptian), UK North Sea
Authors: Ainsworth N. R. , Riley L. A. , Gallagher L. T.
Published: November 2010

A Lower Barremian–Upper Aptian lithostratigraphic scheme applicable to the Britannia Field (Blocks 15/29, 15/30, 16/26 and 16/27) is presented. The Britannia Sandstone Formation reservoir is formally subdivided into three members (type well 15/30-9); the Lapworth (Late Barremian to Early Aptian), Kilda (Late Aptian) and Bosun (latest Aptian) members. The Lapworth Member is subdivided into three units, Lapworth ‘A’ (Late Barremian), the intra-Fischschiefer Lapworth ‘B’ (intra-Early Aptian) and Lapworth ‘C’ (Early Aptian).

The Early Barremian to Early Aptian upper Valhall Formation is subdivided into seven units: ‘V3A’ the Hauptblatterton, ‘V3B’, ‘V3C’, ‘V3D’, Fischschiefer Bed, and ‘V4’. The overlying Sola and Rodby Formations are subdivided into Units ‘S1’ and ‘S2’ of the ‘Lower’ Sola Formation (Late Aptian), plus Units ‘S3’ and ‘S4’ of the ‘Upper’ Sola Formation (Early Albian). The Rodby Formation (Middle? to Late Albian) is subdivided into three units: ‘R2’, ‘R3’ and ‘R4’.

A high resolution biostratigraphic zonal scheme is defined for the Early Barremian to earliest Albian interval, utilizing calcareous nannoplankton, micropalaeontology and palynology. Within this, 49 zones and 38 subzones (12 microfaunal zones and 4 subzones, 23 palynological zones and 19 subzones, and 14 nannoplankton zones and 15 subzones) are recognized. Of these, 5 micropalaeontological zones (and 4 subzones), 11 palynological zones (and 15 subzones) and 7 calcareous nannoplank-ton zones (and 10 subzones) are directly applicable to the Britannia reservoir section.
Sediment transport and dispersal pathways in the Lower Cretaceous sands of the Britannia Field, derived from magnetic anisotropy
Authors: Hailwood Ernie , Ding Fung
Published: November 2010

Sediment transport directions and dispersal patterns in the Lower Cretaceous sands of the Britannia Field have been investigated, using magnetic anisotropy and palaeomagnetic core re-orientation methods, to aid understanding of the geometry and architecture of the reservoir sand units. The results indicate that sands were sourced mainly from the north. This applies both to the massive sand bodies with lobate geometry in the lower reservoir zones in the western part of the field and to the laminated slurried beds with tabular geometry in the upper zones in the eastern part. Thus, sediment in this part of the Outer Moray Firth play appears to have been derived largely from a discrete point source to the north rather than from axial flow along the Witch Ground Graben.
Evaluation of a New Method to Build Geological Models of Fractured Reservoirs Calibrated to Production Data
Authors: Rawnsley Keith , Wei Lingli
Published: November 2010

A new methodology to describe fractured reservoirs by construction of geological models calibrated to well test data is evaluated by case application. The aim of the approach is to construct a three-dimensional (3D) fracture/matrix model that represents the main components of the reservoir architecture. The model allows a close approximation of complex geological features. The geological model is calibrated against well tests to determine the geometrical and single phase flow properties required to reproduce the well test. This process may allow discrimination between different equally plausible geological scenarios and the output of the approach has implications for input to reservoir simulators.

Input to the model includes the seismic-scale reservoir structures, the geological layering and observed intersections with flowing fractures in wells. A structural model is built within this framework in accordance with the geologist’s understanding of the fracture system and geomechanical principles. The structural model is comprised of surfaces, which may represent individual fractures or, alternatively, may represent more complex geological features including fractured layers or fault zones. The matrix is represented either implicitly or explicitly.

A case application is described where three well tests in the same reservoir volume are modelled. All three well tests were matched within the same internally consistent geological model, which previously had not been achieved using standard analytical well test analysis tools. This may illustrate the advantage of utilizing a more realistic geological model. Having established a series of models consistent with both the geological and flow data it becomes possible to identify the key components of the model that must be represented in a reservoir simulation model.
Increasing production from old, onshore oil fields, Azerbaijan –a case study
Authors: Griffths A. E. , Begliarbekov V. R. , Shakbazov M. A. , Sultanov P.
Published: November 2010

As part of an effort to try to halt the decline in onshore oil production and accelerate production from onshore fields in Azerbaijan, a World Bank-sponsored study of four fields was carried out: the Bibi-Eybat, Kala, Buzovni-Mashtagi and Zirya fields. The study integrated geoscience, engineering, economics and environmental issues. This paper concentrates on the determination of methods for increasing production rates and recovery. The characteristics of the subject fields are summarized and their current status described. Methods for improving oil production rates in the fields include: mechanical work-overs, artificial lift optimization, sand-control and changes to well completion practices. Our work indicates that production rates could be raised between two-and ten-fold through the application of modern oil-field practices, but financial constraints have prevented their widespread use. Well intervention techniques form the basis of several outline field development plans, described with the associated production forecasts. A brief review is made of possible exploration plays which exist in and around the subject fields.
Application and implication of horizontal well geochemistry
Authors: Wilhelms A. , Rein E. , Zwach C. , Steen A. S.
Published: November 2010

This paper describes the application of horizontal well geochemistry for the first time. Closely spaced samples, taken along a horizontal or deviated well path, allow the identification of reservoir compartments. Significant variations in geochemical parameters are related to the field filling and, if they persist over geological time and over tens of metres, should reflect barriers to diffusion and, by inference, possibly also to fluid flow.

Two different approaches have been chosen: (a) closely spaced head space gas samples; (b) wet cuttings-based techniques. Case studies are presented documenting the detection of sealing faults between different reservoir compartments at the time of sampling. This novel approach has several advantages: (i) the need for costly pressure measurements is reduced; (ii) high sample density allows better spacial definition of barriers compared to both seismic and pressure measurements; (iii) detection of sub-seismic barriers; (iv) it allows detection of compartments even in cases where no pressure differences exist; (v) the technique works in wells drilled with oil-based mud systems. The strong variations in the geochemical signal over short distances has implications for the filling of reservoirs. The data suggest that reservoir filling is far more complex than previously envisaged.
Blenheim Field: the Appraisal of a Small Oil Field With a Horizontal Well
Authors: Dickinson B. , Waterhouse M. , Goodall J. , Holmes N.
Published: November 2010

Blenheim is a small Palaeocene oil field (
c.
53 × 10
6
BBL oil in-place), in which significant seismic uncertainty complicated a development decision. Initial appraisal plans required a conventional deviated well sited to minimize the uncertainty, gather further reservoir and fluid data, and, if successful, provide a production well.

Later studies indicated improved economics if horizontal wells were successful. Several well designs, with and without pilot holes, were analysed to discover the optimum balance of data gathering, risk reduction and development cost reduction. The optimum well required accurate well steering in an area of seismic uncertainty. A high-resolution biostratigraphic study was made and provided detailed correlation of intra-reservoir mudstones, enabling wellsite analysis to aid steering decisions.

The pilot hole proved the most likely seismic interpretation to be correct and permitted the horizontal well to be drilled as planned. Wellsite biostratigraphic analysis and real-time MWD aided steering decisions and contributed to a successful horizontal well being drilled. The well flowed in excess of the minimum economic rates required and allowed the field to be successfully developed.
Production of gas from waterflood residual oil: gas saturation build-up and relative permeabilities
Authors: Grattoni C. A. , Hawes R. I. , Dawe R. A.
Published: November 2010

When solution gas is released from waterflooded residual oil by depressurization, the gas becomes mobilized after the critical gas saturation has been reached, but the gas saturation continues to increase as more gas is generated. The rate of gas saturation change plus the unrecoverable gas (gas saturation remaining at the end of the depressurization) are important in determining the economic performance of the process. The values depend upon the rate of gas generation and the gas relative permeability.

Experiments are reported to measure water and gas relative permeabilities when gas is released from waterflooded residual oil. The values for the gas phase were extremely low, approximately an order of magnitude lower than would be predicted using a Corey-type equation suggesting that gas relative permeabilities measured in normal gas–water displacement experiments are not applicable to the depressurization of waterflooded reservoirs.

The low values of gas relative permeabilities can be explained by the fact that the filaments which form the channels for gas flow are not stable, and that the flow is intermittent. Visual observations of the flow behaviour in micromodels have confirmed this. As a result, the effective total area for flow at any particular gas saturation is substantially reduced, thus reducing the permeability to the gas. New algorithms need to be introduced into the network models for estimating relative permeabilities in these situations before they can be used to represent the cyclical nature of filament rupture and reformation.
Underground gas storage: estimating gas column height and saturation with time lapse seismic
Authors: Dumont Marie-Hélène , Fayemendy Cédric , Mari Jean-Luc , Huguet Frédéric
Published: November 2010

Seismic monitoring is often used to check hydrocarbon movements during production. On the site of Céré-la-Ronde, an underground water-bearing gas storage facility developed by Gaz de France, a methodology has been implemented for estimating gas column height and saturation with time lapse seismic. The methodology is based on the Gassmann model, on the measurement of time-shifts and on the computation of a specific seismic function. The time-shifts obtained by cross-correlation techniques are used to derive the residual time-shift Δ
t
induced by the presence of gas within the reservoir. A specific function is used to estimate both the gas bubble extension and the gas time thickness
H
t
. It is shown that knowledge of
H
t
and Δ
t
and the use of a Gassmann model can lead to an estimation of the gas saturation. The methodology has been applied successfully on conventional seismic profiles as well as on vertical seismic profiles (VSP). The results obtained with seismic data are in good agreement with those obtained by logging (sonic and neutron logs) but with a lateral investigation, which is much larger than the one given by logging techniques. In our field example, the gas anomaly has been checked over a distance of 300 m with VSP data and over 2 km with surface seismic data.
Outcrop-based stochastic modelling of turbidite amalgamation and its effects on hydrocarbon recovery
Authors: Stephen Karl D. , Clark Julian D. , Gardiner Andy R.
Published: November 2010

In sandstone-dominated successions of sheet-like turbidites, erosion of thin shale horizons during deposition of the overlying turbidite may lead locally to vertical amalgamation of sandstone beds, resulting in discontinuous thin fine-grained beds or, in the extreme case, thoroughly amalgamated sandstone. Measurements of discontinuous shale lengths from very well exposed turbidite successions have enabled the development of a mixed rule-based/stochastic model for the erosion of shales. Monte Carlo realizations of 2D cross-sections were used to examine the effects of shale discontinuities on both single-and two-phase flow, at the genetic sedimentary unit scale. Results demonstrate that the flow is strongly dependent on the balance of viscous, capillary and gravity forces, which can vary according to the distribution of amalgamation surfaces. The single-phase upscaled ratio of horizontal to vertical permeability and the fraction of mobile oil recovered can be related to the fraction of shale removed (amalgamation ratio) by log-linear and linear relationships respectively.
Stress orientation, pore pressure and least principal stress in the Norwegian sector of the North Sea
Authors: Grollimund Balz , Zoback Mark D. , Wiprut David J. , Arnesen Linn
Published: November 2010

We have compiled data on stress orientation, pore pressure and least principal stress from over 300 wells in the Norwegian sector of the North Sea. Well-defined regional variations are observed in all three parameters. Incorporation of precise stress orientation data from drilling-induced tensile borehole wall fractures shows that the orientation of maximum horizontal stress is approximately E–W between 60°N and 62°N but tends to be NNW–SSE south of 58°N, similar to the average stress direction seen throughout Great Britain and continental NW Europe. We believe this rotation is due to the superposition of plate-driving stresses with those associated with lithospheric flexure caused by deglaciation. Regional variations of the magnitude of the least principal stress and pore pressure also appear to support the hypothesis that the stress field in this region has been strongly affected by deglaciation.
Permeability prediction using stress sensitive petrophysical properties
Authors: Jones C. , Somerville J. M. , Smart B. G. D. , Kirstetter O. , Hamilton S. A. , Edlmann K. P.
Published: November 2010

The correlation of stress sensitivity to various petrophysical parameters was studied by analysis of experimental results from a range of sandstone core plugs tested hydrostatically at room temperature. The parameters measured were: compressional wave velocity, porosity, permeability and electrical resistivity. More detailed information on the effects of sorting and grain size distributions was obtained from experiments on artificial, unconsolidated sandstone cores. The measurements showed a high degree of stress sensitivity, which was different for each core but, broadly, could be classified as either high or low stress sensitivity. Cores from the high permeability clean sand were less stress sensitive than the cores from the low permeability coarsening-upwards sequence and the petrophysical values when combined into a synthetic log distinguished between the two lithologies. The results were compared to the predictions of a simple asperity deformation model. The experimental results and the model suggested a possible logging strategy to deduce permeability, by varying wellbore pressure.
A statistical method for correcting log-derived temperatures
Authors: Waples Douglas W. , Ramly Mahadir
Published: November 2010

Statistical analysis of subsurface temperatures in the Malay Basin has been carried out in order to (1) determine appropriate correction methods and correction factors for temperatures obtained from wireline logs and (2) investigate the confidence levels associated with those corrections. DST temperatures were taken as ‘ground truth’ for these corrections. For individual log-derived temperatures the correction factor
f
S
, which is applied to the difference between the measured temperature and the surface temperature, is given by

f
s

=
(
−
0.1462
Ln
(
TSC
)
+
1.699
)
/
(
0
.
572
⋅

Z

0.075

)
,

where TSC is the time since end of mud circulation in hours and
Z
is the depth in metres. For temperatures that have already been corrected by extrapolation using Horner plots,
f
HP
is given by

f

HP

=
−
0.1321
Ln
(
TSC
)
+
1.52
,

where TSC is the maximum time since circulation stopped (hours) in the Horner plot set.

Uncertainties in
f
S
decrease markedly as TSC and depth increase. Uncertainties in
f
HP
decrease as maximum TSC and the number of consistent temperature measurements at a given depth increase.

Although these correction factors were developed using data from a single basin, our experience suggests that they can be used with reasonable confidence in many or most other geological provinces. Additional local calibrations would help test and refine this hypothesis.