bluuebunny/crossref_metadata_2025_split huggingface dataset:
The ‘tight gas’ challenge: appraisal results from the Devonian of Algeria
Authors: Hirst J. P. P. , Davis N. , Palmer A. F. , Achache D. , Riddiford F. A. 
Published: November 2010

Projected future increases in Algerian gas production will, in part, come from more complex reservoirs within the Ahnet-Timimoun Basin; here, conventional quality reservoirs (>1 mD) are interbedded with volumetrically significant, low permeability sandstones (<1 mD) – the ‘tight gas’ sandstones. The challenge has been to develop a programme of work which will establish reserves in this sub-millidarcy resource; on balance, the results of this evaluation programme are positive.
The main tight gas sections are of Lower Devonian age. Grain rimming chlorite cement within thin intervals locally inhibited later pervasive quartz cementation; the quartz is the cause of reservoir degradation in the bulk of the sandstone resulting in permeabilities of <1 mD, and often in the microdarcy range. Generally, the Lower Devonian has a low density of faulting and fractures; open and closed fractures are observed in core, whilst mud losses suggest some fractures are conductive in the subsurface.
One of the main structures, the Teguentour Field, has been evaluated through the drilling of two new wells. The first of these wells (Teg-14) evaluated interbedded tight and conventional sandstones, whilst the second (Teg-15) was a dedicated tight sandstone completion involving an induced fracture programme.

The permeability range in the tight gas sandstones extends below the resolution of conventional porosity/permeability measurement; determination has been improved through mercury injection derived permeabilities. Water saturations determined from core and log suggest gas may be present in the low permeability rock. The presence of gas could not be confirmed by formation tester samples and thus dynamic data were required from the Teg-15 well which was completed within the tight sandstone interval; only the top 5 m was perforated to limit the possibility of a communication pathway down to conventional quality sandstones. After nitrogen lift, the well flowed gas to surface at
c.
5 ×10
4
SCFD for several hours. The low leak-off coeffcient determined suggests there was no connection to a pervasive conductive fracture network, although fractures intersected by the wellbore may have contributed to flow. Also, large poro-elastic back stresses indicate that a connection to high matrix or fracture permeability was unlikely. On balance, the test is a positive indicator of gas presence in very low permeability/porosity rocks which may recharge associated conventional layers following suffcient drawdown.
Exploration for and development of hydrocarbons in the Chalk of the North Sea: a low permeability system
Authors: Megson Joan , Hardman Richard 
Published: November 2010

It is evident that all or most North Sea Chalk fields have dipping oil–water contacts and that some also have dipping free water levels. Furthermore, there are Chalk fields, such as South Arne (Denmark) and Joanne (UK) with steeply dipping oil–water contacts and a large element of non-structural trapping, while other discoveries, such as the recent Halfdan discovery northwest of the Danish Dan Field, have no element of structural trapping and appear to lie on a Tertiary migration pathway. It is also evident that the presence of North Sea Chalk oil, both as fields and shows, is localized and, generally, confined to areas of early source maturation – although there are exceptions, such as the UK Fife and Flora Chalk oil accumulations, which are distant from a source basin.
We believe that these attributes reflect the same cause, that is the very low lateral and vertical permeability (typically 0.1 to 1 mD air permeability) of the Chalk system. Our hypothesis is that oil enters the Chalk from the Jurassic at a limited number of entry points within the early mature basin and, only if the oil reaches Chalk of relatively high permeabilities, normally the Tor Formation, does the oil migrate significant distances laterally. This oil migration occurs at geological timescales, i.e. kilometres over millions of years and we, therefore, have to consider the configuration of the Chalk – with respect to migration routes and traps – at the time the oil was injected into the Chalk and began to migrate through it, which was normally prior to the North Sea Miocene inversion and later tilting. There is considerable evidence for trapping in Chalk palaeostructural traps; oil migrated into a palaeohigh, segregated vertically and is trapped by the low oil relative permeabilities within the transition zone when the trap later tilts. Another trapping mechanism is the migration trap, as described for the Halfdan discovery in Denmark, where, in an area mature for Chalk exploration, oil has been discovered in continuity with the Dan Field but with a free water level 700 ft lower. This type of trap may contain significant reserves of oil in chalks of 1 mD permeability and, in recent years, it has become possible to exploit chalks of this nature commercially. It is also possible to develop these chalks when no effective natural fracture system exists.
The seismic evaluation of a naturally fractured tight gas sand reservoir in the Wind River Basin, Wyoming
Authors: Bates C. R. , Phillips D. R. , Grimm R. , Lynn H. 
Published: November 2010

Sub-vertical natural fracturing is critical for ensuring economic gas production from tight sand reservoirs in many provinces. Over the last seven years, the US Department of Energy (DoE) has sponsored a series of programmes in the continental United States to develop cost-effective technologies for investigating naturally fractured reservoirs. The results from a study of a Laramide-age faulted anticline reservoir in the Lower Fort Union Formation of the Wind River Basin, Wyoming are presented. At the field site a multi-azimuth, multi-offset 3D compressional wave seismic survey was acquired and processed using azimuth-dependent processing followed by multi-azimuth attribute analysis. Geophysical attributes such as velocity, frequency, reflectivity and amplitude variation with offset, together with geological attributes such as depth below closure and distance from faults, were correlated to estimated ultimate recovery of gas for established wells within the field. The correlations were made using linear statistical methods, non-linear rank methods and neural networks to combine attribute results. The geophysical attributes and other geological information were combined into prospectivity maps for areas of highest fracture density. Based on the geophysical and geological results an 80% success rate was achieved at prospecting well locations.
A major aspect of the DoE programmes has been the investigation of costeffective protocols for fracture detection. From this study the following procedure is recommended for cost-effective mapping of fractures and associated gas: (1) perform field and remote-sensing reconnaissance of structural trends; (2) acquire 3D P-wave surveys with offsets equal to or greater than target depth in all azimuths; (3) process in at least two dominant structural azimuths; (4) combine best correlated geophysical and geological attributes to fractures for future fracture zone mapping. The implications of the results from this survey have important consequences for the design and implementation of multi-azimuth, multi-offset data acquisition on land and for marine surveys where multi-component ocean bottom cable surveying is used.
Fluvial reservoir architecture in the Statfjord Formation (northern North Sea) augmented by outcrop analogue statistics
Authors: Dalrymple Mark 
Published: November 2010

Outcrop data from the fluvial/incised valley systems of the Cretaceous Straight Cliffs Formation of southern Utah, USA, are applied to the subsurface fluvial reservoirs of the Statfjord Formation. Aspect ratios (width:thickness) for fluvial sandbodies have been measured from large-scale cliff exposures. This database provides the lateral extent, or width, of any fluvial sandbody, given the thickness for that sandbody and the net-to-gross of the interval in which it is preserved. This allows prediction of a probability distribution for fluvial sandbody width from one-dimensional vertical well data.
The outcrop data are applied to one well in each of the Brent, Statfjord and Snorre fields, through similar stratigraphic intervals, to allow comparison of the various sandbody architectures which result from the same outcrop dataset. Various fluvial architectures are identified: from high net-to-gross and high connectivity, to low net-to-gross with low sandbody connectivity.
Ranking of stochastic realizations of complex tidal reservoirs using streamline simulation criteria
Authors: Brandsæter Inge , Wist Hanne Therese , Næss Arve , Lia Oddvar , Arntzen Ole Jakob , Ringrose Philip S. , Martinius Allard W. , Lerdahl Thomas Rage 
Published: November 2010

This study concerns the modelling of complex tidal heterogeneities found in the Lower Jurassic Tilje Formation offshore mid-Norway. The Tilje Formation is characterized by tidal channels, tidal bars (shoals), tidal flats and deltaic deposits. The lithofacies associations have been modelled as large-scale objects with a wide range of shapes (channels, sheets and lobes). In addition small-scale models of the internal bedding structure have been generated in order to calculate effective permeability values at appropriate modelling scales.
In order to assess the influence of the static input factors on recovery predictions, several production response variables were recorded for each of the 120 realizations generated. These include: streamline densities, breakthrough time measured in movable pore volume injected, pore volume tracer injected at 50% and 95% tracer fraction in the producer, and recovery factor of movable pore water at 95% tracer fraction in the producer. For this purpose we used a streamline reservoir simulator (Frontsim) with a tracer option (single-phase flow simulations).
By using analysis of variance, we identified the following parameters which have the largest influence on single-phase fluid flow: (1) dimension of large-scale bar objects; (2) effective permeabilities of marginal (background) facies; and (3) interaction effects between bar objects and background permeabilities. In addition, the effective permeability values of the marginal facies are highly controlled by certain thresholds in mud content.
Integrated scenario and probabilistic analysis for asset decision support
Authors: Floris Frans J. T. , Peersmann Martin R. H. E. 
Published: November 2010

In recent years, much effort has been spent in integration of the hydrocarbon E&P business processes. The new challenge lies in the use of the generated data for decision-making. In particular, in hydrocarbon assets, where large uncertainties occur, it is important to include the formal quantification of these uncertainties in the integrated workflow and allow for a decision framework based on a full characterization of these uncertainties.
For quantification of uncertainties two classes of approach are currently in use –the probabilistic approach based on the description of a stochastic model for capturing all uncertainty and the scenario approach based on a definition of a number of conceptually different models expressing the uncertainty. Some hybrid versions of the approaches exist as well. The pros and cons of these approaches are discussed. Following this, an extended statistical framework is presented in which the previous approaches to subsurface uncertainty modelling have been combined. The framework is not limited to subsurface uncertainties, but can also be applied to the other uncertainties and decisions in the asset model. In the integrated framework several scenarios may be identified for the static earth model, the dynamic earth model, the drilling model, the surface facilities model and the economic model. A scenario tree can represent the combination of all these scenarios.
Within each scenario a stochastic model can be applied to capture the within-scenario uncertainty. Calculation rules for the integration of the stochastic and scenario uncertainties are presented. Finally, decision rules are given that allow for decision-making based on the full uncertainty span in the integrated asset framework.
Synthetic well test modelling in a high net-to-gross outcrop system for turbidite reservoir description
Authors: Robertson Ewan , Corbett Patrick W. M. , Hurst Andrew , Satur Nick , Cronin Bryan T. 
Published: November 2010

Synthetic well tests have been produced using a 3D model of an outcropping turbidite sandstone unit from the Cingöz region in southern Turkey. The model contains realistic sand sheet, tongue, lobe and background sand facies architecture (i.e. geometry and stacking) mapped from an outcrop study. The geometric information is useful as an analogue for high net-to-gross turbidite oil fields. The facies have been assigned petrophysical properties from a subsurface analogue. There is little shale in this system. Well test responses were then derived from the high net-to-gross turbidite model using various architectural, porosity–permeability scenarios and completion strategies. The impact on well test derivatives of various sand body geometries and permeability contrasts could then be determined. Two completion strategies – partial penetration and fully perforated intervals – were assessed for their applicability in the high net-to-gross system.
The geological model is effectively a sandbox, and shows a very uniform testing response from the rather uniform property distributions. However, when the level of permeability heterogeneity is increased by populating the model with varying contrasts of permeability and porosity, the sand body geometry can be seen to influence the well tests. Partial completions in sand bodies are particularly effective in detecting sand body geometry. The geometry controls the flow regimes in a well test response despite variations in the permeability contrasts. The effect of varying geometry is illustrated and an external linear flow regime is identified. Where there is sufficient sand body thickness, partial perforation results in spherical flow, from which a vertical permeability can be obtained. In the model, the vertical permeability thus obtained is a local (to the volume investigated) effective permeability of stacked isotropic facies.
This work was undertaken to give guidance on the description of hydrocarbon reservoirs by well testing. If well testing is to be used in high net-to-gross turbidite systems for the purposes of reservoir characterization, then partial perforation of the system should be planned. Interpreted vertical permeabilities should be applied with careful consideration of the stacked pattern of sand bodies.
Multi-target wells: a new concept to improve well economics
Authors: Sackmaier W. E. 
Published: November 2010

The Vienna Basin is a sedimentary basin more than 10 km in thickness and composed of more than a dozen hydrocarbon layers. Since the area has been intensively explored in the past 50 years, future exploration can expect to find only small reservoirs or compartments of already existing reservoirs. However, the existing infrastructure, such as pipelines, facilities and a nearby refinery, would make even small finds attractive. In this light it is of vital importance to reduce risk and costs in hydrocarbon exploration and production.
Multi-target wells were found to be an adequate answer to these problems: the chance of discovery increases more or less directly with the number of targets included in the well trajectory; and several small reservoirs can, in total, provide positive well economics. Moreover, by including exploration, appraisal and production targets into one well path a substantial contribution to improve economic hydrocarbon recovery from existing fields can be made. To further reduce drilling costs a new casing philosophy was established. By skipping the intermediate casing across the build-up section substantial savings could be made.
To plan and execute these challenging projects efficiently a multidisciplinary team has to be set up at an early stage of the drilling project. In this way the number of targets, the actual well path and well construction with respect to production requirements can be optimized. An example of a recently drilled multi-target horizontal well, including one primary and five secondary targets, is given. By applying this new concept drilling costs could be reduced by more than 30%.
Fluid saturation from well logs using committee neural networks
Authors: Helle Hans B. , Bhatt Alpana 
Published: November 2010

Neural computing has made a major step forward by the introduction of multi-net systems in practical applications. In this study we developed and tested a modular artificial neural network system for predicting underground fluids, water, oil and gas, and their partial saturations, directly from well logs, without explicit knowledge of the fluid and rock properties as required by conventional methods. Based on laboratory data on relative permeability for alternative fluid systems –oil–water or gas–oil – respectively, relative permeability logs may also be provided for input to reservoir simulation while drilling.
Simple three-layer back-propagation artificial neural networks (ANN) constitute the building blocks of a modular system, where the input logs are sonic, density, neutron porosity and resistivity. By numerical experiments using synthetic logs we have determined the optimal architecture of the ANN. We find that the overtraining strategy is a suitable technique for bias reduction and an unconstrained optimal linear combination is the best method of combining outputs in the committee neural net. The accuracy of the net is restricted only by accuracy of data. Comparison between ANN predictions of fluid saturation with those of conventional petrophysical analysis, in wells unknown to the network, indicates a standard error of less than 0.03.
Prediction of offshore viscous oil field performance using reservoir simulation
Authors: Balbinski E. F. , Element D. J. , Goodyear S. G. , Jayasekera A. J. 
Published: November 2010

Development plans for UKCS viscous oil reservoirs use production profiles predicted by full-field simulation models. The use of horizontal wells, possibly combined with other IOR techniques, and the unusually high vertical permeability of many of the fields, lead to a range of issues that need to be carefully considered when building simulation models.
The strengths and weaknesses of different gridding systems, and the level of areal and vertical grid refinement that is needed, are discussed and illustrated with a range of examples including: interpretation of Extended Well Test results and integration with full-field modelling; sensitivity to relative permeability assumptions; prediction of gas movement from primary gas caps; and the comparison of different IOR techniques.
Where horizontal wells are drilled to reduce gas coning, undulations in the well trajectory can cause local coning of free gas, giving significantly earlier breakthrough times compared to strictly horizontal wells. A good correlation is found between effective stand-off and breakthrough time. Where localized gas production occurs, scoping calculations suggest that inflow of oil from further down the wellbore may be significantly reduced by multi-phase friction effects and gravity potential terms not modelled in conventional simulators.
Quaternary lithology and shallow gas from high resolution gravity and seismic data in the central North Sea
Authors: Bauer Christian , Fichler Christine 
Published: November 2010

High resolution marine gravity data and 3D post-stack seismic data from the central North Sea have been jointly interpreted. The accuracy of the gravity data allowed the detection of density contrasts related to a Quaternary sub-glacial melt-water channel, a shallow gas accumulation and a Tertiary gas chimney. The combination of gravity and seismic data is shown to particularly improve the detection of the shallow gas accumulation.
The interpretation included visual correlation of gravity images and seismic data performed in a seismic workstation environment, as well as 2.5D gravity modelling along selected seismic profiles. The successful application of this method on shallow targets requires a limited complexity of the shallow strata as well as targets defined by a distinct density contrast and a reasonable size. Data requirements include high-resolution bathymetric and free air gravity data. Bouguer gravity data, which are commonly used in exploration, cannot be used here as densities may vary within the uppermost layer below the sea bottom.
How can we help ensure success of oil and gas field rehabilitation projects?
Authors: Heward Alan P. , Gluyas Jon G. 
Published: November 2010

Oil field redevelopments or rehabilitation projects have become commonplace within the past decade. There are a number of reasons for this, not least that large old fields often contain significant quantities of remaining petroleum. Other major factors are that countries rich in petroleum but hitherto inaccessible to western oil companies have opened up their fields and as the world’s basins become thoroughly explored, field redevelopments look more attractive as the prospects for frontier exploration diminish.
Although now commonplace, field rehabilitations differ widely from redeveloping one’s own field in a familiar basin to entering a new country to work on an aging giant accumulation. The chance of success also varies widely, with modest redevelopments of one’s own fields commonly achieving success but bold forays into new countries and old fields often heralding commercial failure.
There are a number of actions that can be taken to improve the chance of success for any rehabilitation project. The selection of people forming the teams involved in evaluation and implementation requires considerable attention. If overseas, build on the know-how and experience of national staff. Every effort must be made to understand how the field performed and was worked in the past. The old well and production data need to be gathered, sorted, interpreted and made accessible to all in the project. The initial redevelopment targets must be modest, testing of hypotheses rigorous and acquisition of monitoring data on such pilot schemes extensive. ‘New technology’ may help but it is unlikely to be a panacea. Major financial outlay on, for example, new facilities should not be made until an understanding is achieved of how new wells and completions behave during production. Finally, success should be celebrated when success happens rather than celebrating proffered success before the project begins.