New reservoirs are increasingly more heterogeneous and more anisotropic. Unfortunately, conventional reservoir modelling has a resolution of only about 50 m, which means it cannot be used to model heterogeneous and anisotropic reservoirs effectively when such reservoirs exhibit significant inter-well variability at scales less than 50 m. This paper describes a new fractal approach to the modelling and simulation of heterogeneous and anisotropic reservoirs. This approach includes data at all scales such that it can represent the heterogeneity of the reservoir correctly at each scale. Three-dimensional Advanced Fractal Reservoir Models (AFRMs) can be generated easily with the appropriate code. This paper will show: (i) how 3D AFRMs can be generated and normalised to represent key petrophysical parameters, (ii) how these models can be used to calculate permeability, synthetic poro-perm cross-plots, water saturation maps and relative permeability curves, (iii) the effect of altering controlled heterogeneity and anisotropy of generic models on fluid production parameters, and (iv) how AFRMs which have been conditioned to represent real reservoirs provide a much better simulated production parameters than the current best technology. Results of generic modelling and simulation with AFRMs show how total hydrocarbon production, hydrocarbon production rate, water cut and the time to water breakthrough all depend strongly both on heterogeneity and anisotropy. The results also show that in heterogeneous reservoirs, the best production data is obtained from placing both injectors and producers in the most permeable areas of the reservoir – a result which is at variance with common practice. Modelling with different degrees and directions of anisotropy shows how critical hydrocarbon production data depends on the direction of the anisotropy, and how that changes over the lifetime of the reservoir. We have developed a method of fractal interpolation to condition AFRMs to real reservoirs across a wide scale range. Comparison of the hydrocarbon production characteristics of such an approach to a conventional krigging shows a remarkable improvement in the modelling of hydrocarbon production when AFRMs are used; with AFRMs in moderate and high heterogeneity reservoirs returning values always within 5% of the reference case, while the conventional approach often resulted in systematic underestimations of production rate by over 70%.

The joint research project "MUM - Large Modifiable Underwater Mothership" targets the development of a highly modular, unmanned underwater vehicle, which allows a mission dependent module assembly to fulfill a wide spectrum of underwater tasks. The paper presents a case study for the deployment and recovery of ocean bottom nodes (OBN) for seismic surveys. Therefore, a specific vehicle configuration and its functionality is introduced. The advantages of MUM are presented in terms of its cost efficiency and non-monetary benefits, as crew safety, carbon footprint and others. In addition, business aspects for potential customers are discussed.

This paper describes the proposed re-development of the Galapagos Field, comprising the abandoned NW Hutton field and the Darwin discovery (Block 211/27 UKCS) which forms a southerly extension. The paper covers the initial concept and analytical evaluation, the static uncertainty model build, the dynamic model history-match, the iterations between static and dynamic modelling, the development subsea and well locations, the optimisation workflow of the advanced Flow Control Valve (FCV) completions in both producers and injectors and the facilities constraints. The redevelopment plan involved several multi-disciplinary teams. 20 years of production data from 52 wells were analysed to identify the production behaviour and confirm the significant target that provided the basis for the development concept selection. The full Brent sequence compartmentalised stochastic static model was based on reprocessed seismic plus 14 exploration and appraisal wells. Streamlines, uncertainty sensitivities and mostly good detective work honed a history match to RFT, BHP, PLT and oil and water production. P50, P90/P10 models were selected and over 100 FCVs optimised to deliver the profiles against an identified FSPO facilities’ constraints. Over 1,000 static models were delivered consisting of sheet sands, incised valleys and channels in heterolithic facies overprinted by a depth trend with appropriate uncertainty ranges. The high well count gave a tight STOIIP probabilistic range of 790/883/937 million stb. The early RFTs illustrated extreme differential depletion between Brent zones and subzones of the Ness. To history-match these the dynamic model retained the static model definition in the Upper Ness to capture the thin but extensive shales. The early 18-month depletion and the late steady production-injection phases were simulated separately in prediction mode and matched the Production Analysis estimated ‘future’ production giving confidence to the history matched model. The initial concept development of 4 subsea-centres, to cover the large field area, with an injector in each compartment proved a robust selection. The horizontal wells increase PI where needed and mitigate internal faulting. The optimisation of the FCVs significantly increased oil production from all zones and drastically reduced water injection and production so that the identified FPSO modifications were relatively modest. The final First Stage Field Development Plan consists of 11 producers and 6 injectors across developed and undeveloped areas confirmed robust P50 reserves of 84 million boe. Robust concept selection allowed for early identification of production units so that constraints and modifications could be accounted for within the economic model. The Galapagos field re-development plan is an excellent example of how detailed static and fully history matched dynamic models can lay the foundations for new technology like the optimisation of the FCVs to access bypassed reserves using significantly smaller production units with reduced requirements for power, compression, gas lift, pumping pressure, injection and production. In short, they shrank the facilities.

As part of the planning for development drilling on the North Sea Catcher fields in 2015, Premier Oil sought technology solutions that would aid in drilling the complex injected sand reservoirs. Due to the highly variable and potentially discontinuous nature of injected and remobilized sand reservoirs, operators have historically had to drill multiple sidetracks and the utility of drilling pilot holes to reduce depth uncertainty was of particular concern. Pilot holes in injectite reservoirs have seen variable success, as the positional information obtained can only be extrapolated over short distances due to rapid changes in reservoir form and stratigraphic position. The complex 3D architecture of injectites also poses challenges in drilling horizontal wells, leading to difficulties in optimizing well placement, with an increased risk of having to carry out a geological sidetrack, and an increased risk of sidetrack failure due to missing reservoir or shale instability. Moreover, pilot holes and sidetracks come with their own drilling challenges, be it technical or financial. To help de-risk these challenges, Premier Oil selected the Deep Directional Resistivity (DDR) logging while drilling tool to map and to help understand these complex injectite reservoirs. With a depth of investigation of up to and in excess of 30m (100ft) TVD from the wellbore, the service enabled the Premier Oil and Schlumberger Well Placement team to map the injectites complex external geometries and internal architectural features in real-time. Being able to resolve the form of the injectite reservoir in real-time provided the team the ability to use this wellbore-to-reservoir scale information to tie the position of the reservoir to the seismic data. From this it has been possible to forward project wellpaths and make informed geosteering decisions as wells drill ahead and new data is acquired. This ability to map and proactively geosteer, both on landing and within reservoirs in real-time, has helped Premier Oil to avoid both pilot holes and geological sidetracks. In this paper three case studies are showcased. The first case demonstrates how the requirement of a pilot hole was eliminated by using the DDR technology. The second and third case studies illustrate the quantitative assessment of sidetrack risking and how data collected during drilling enabled optimum well placement via azimuthal geosteering and hence the avoidance of a possible sidetrack during the horizontal reservoir sections.

The field of seismic full-wave inversion (FWI) and high-resolution reservoir simulation are in a transition period where methods based on simplified wave propagation and flow physics phenomena are successively replaced by fully numerical approaches of dense earth model representations running on high-performance computers (HPC) that allow exploration geophysicists and reservoir engineers to unlock, leverage tomorrow's reserves and mitigate subsurface uncertainties in a cost-effective way. The objective is on the one hand to exploit the complete seismic recordings for the benefit of improved vertical resolution of subsurface elastic anisotropic heterogeneous Earth models; and on the other hand, to understand physics at small scale to improve microscopic recovery and improve reservoir modeling predictability towards optimized field development with proprietary in-house developed technology run on HPC. The promise of elastic FWI for seismic imaging and interpretation is to employ waveforms (raw observed seismograms recorded with long/broad range and densely sampled offset/azimuths and full frequency bandwidth) to account for refractions, reflections and high-order scattering, and make NO physical assumptions in the simulation of any observed amplitudes. However, FWI is an ill-posed problem with non-unique solutions, i.e., many combinations of earth elastic parameters can fit the data equally well. The non-uniqueness of solution triggers the uncertainty in the earth model parameters which equally affect both seismic imaging and reservoir modeling workflows. As a result, there is a need to create multiple sets of models in an attempt to optimally explain the data (seismograms). Therefore, the solution of a seismic inverse problem has very high computational complexity that can only be efficiently handled using high-performance computers (HPC). Such computers contain large numbers of nodes interconnected via the high throughput networks; each node combines conventional CPU cores and GPU (graphic processing units) accelerators. Through a combination of theory, methodology and case studies, we demonstrate the recent progress and value added with cost-effective fit-for-purpose Total's proprietary technology efficiently deployed on heterogeneous HPC to yield new acreages in frontier domains, better characterize/predict subsurface reservoirs, and mitigate the geosciences and drilling uncertainties.

During the late life of the Siri field in the Danish North Sea, an infill water injection well was drilled to provide enhanced reservoir sweep and to help improve tail-end field production. Dynamic reservoir modeling indicated that a down-dip horizontal water injector on the southwestern flank of the field using injection inflow control devices (ICDs) could provide the necessary uplift for producers near the crest of the field. The Siri field is characterized as a high permeability, remobilized glauconitic sand package comprising multiple stacked and amalgamated sand bodies deposited from high density gravity flows in the Paleocene-Eocene Siri fairway. Seismic, well logging, and production data indicate that fluid flow is influenced by vertical and horizontal baffling. The internal flow channeling and baffle effects are likely caused by a combination of siliciclastic diagenesis, subseismic faulting, and multiple calcite-cemented paleo oil/water contacts. These baffles are capable of maintaining significant pressure differentials. They consequently have a major effect on field scale horizontal permeability and reservoir sweep efficiency. During the last decade of drilling horizontal development wells in the Siri area, Dong Energy has obtained extensive in-house experience and knowledge in the use of deep reading resistivity technology for reservoir mapping, as well as in positioning long horizontal development wells in challenging settings, such as ultra-thin reservoirs sands and thin oil columns. This paper discusses the well placement and geological evaluation of the Siri reservoir with regard to the acquired logging while drilling (LWD) data, which includes resistivity inversion, neutron porosity/bulk density imaging, and formation pressure measurements. The well trajectory was adjusted in real time to reduce footage exposure to tight facies, as well as to identify fluid boundaries related to the flow channeling present within the reservoir. Borehole resistivity inversion provides evidence that the mineralized permeability barriers are not always high-angle features. This paper also discusses insights into the Siri reservoir geology in light of the horizontal well data acquisition program and potential implications for future ICD behavior.

The Cygnus gas field is being developed by ENGIE E&P UK Limited in the UK Southern North Sea and is one of the largest discoveries in the Southern North Sea in the last 30 years. The field has two gas bearing reservoirs in the Carboniferous Lower Ketch Member of the Ketch Formation and the Permian Lower Leman sandstone. The Lower Leman Sandstone is the main reservoir target for 7 of the 10 wells in the development. The Lower Leman Sandstone is highly layered comprising fluvial influenced playa shoreline facies. The better reservoir quality intervals are restricted to thinly bedded laterally extensive sand rich intervals related to drier climatic events. Through utilization of reservoir navigation LWD tools the production wells have preferentially targeted these better quality thin intervals in order to maximize well productivity. To geosteer in these sands provided several challenges such as uncertainty in dip and the presence of sub-seismic faults. Furthermore the reservoir shows only subtle variations in log response from Gamma Ray and resistivity tools. This made correlations with offset well data difficult. As a result, the integration of information from multiple LWD tools and types of analysis was required to delineate the geological structure and to identify the stratigraphic position of the trajectory in order to place the well in the target interval. The key data sources for the leman productions wells have been the correlation to offset data, real-time Density images and utilization of Deep Directional Azimuthal Resistivity's. The limit of the Deep Directional Resistivity tool was tested due to the very low resistivity contrast reservoir (commonly 1-2 Ohm.m) but the data has still been utilized during geosteering operations. The quality of the density image data has also allowed for a real-time True Stratigraphic Thickness (TST) calculation service to be provided where extra stratigraphic control was required. Five of the Leman production wells have been successfully drilled and completed with results that were at the high end of expectations. This will contribute to maximizing the productivity for the field. In this paper the case studies showcased will demonstrate the Geosteering methodology utilized in this complex reservoir. For ENGIE, these examples demonstrate the value of investing in technologies for acquiring multiple data sets for successfully Geosteering in challenging geological settings.

Understanding the porosity of gas shale is of great importance in many applications such as for enhanced recovery in gas reservoir. The first step for understanding the above properties is the precise quantification of the structure of the porous media. The structure may be characterised using traditional surface area measurement or mercury porosimetry for pore size analysis. However, these methods would provide data rather on pore sizes rather than their structures and configuration within low permeable samples. Modern 3D and non-destructive imaging techniques such as x-ray microtomography (XMT) provides a more convenient and intuitive alternative technique to scanning electron microscopy. The importance of quantitative pore structure characterization in understanding shale reservoir behaviors and lack of measurement techniques are the two main motivation factors behind this research. In this research three-dimensional x-ray micro tomography (XMT) imaging techniques were used to carry out a three-dimensional pore volume analysis of shale samples based on pores size, structure, geometry and orientation. Two samples with different properties (mainly in mercury intrusion porosity, MIP) were tested. It was found that the overall micro porosity obtained from XMT is about 0.7% and 0.3% for sample 1 and 2 respectively and significantly less than those of MIP. Both samples have very close structure orientation and geometry of the pores.

Analyzing well performance is a complex process that increases in difficulty when multiple reservoir-drive mechanisms are in play in the same reservoir. This paper explores an overpressured, compacting chalk reservoir with high porosity and high oil saturation at initial conditions. The diverse drive mechanisms, experienced through the long production history of Valhall field in Norway, are caused by different degrees of reservoir compaction across the field and the recent waterflood at the crest and northern areas of the field. The purpose of this study is to illuminate the various drive mechanisms experienced in this field. The underlying objective is to understand widely varying Arps b -factors in decline-curve analysis (DCA) that support production forecasting and project evaluation. The performances of inactive wells with long production histories were used as analogs to analyze active wells. Other analytical tools were also used to augment overall understanding of a type well's performance, including rate-transient analysis (RTA) and capacitance-resistance modeling (CRM). This study demonstrates that the proposed workflow for reservoir performance forecasting can be adopted in highly complex reservoirs with different rock mechanical properties, drive mechanisms, production scheduling, and field development strategies. Specifically, the workflow entails establishing energy support for individual wells using Arps b -factor with DCA; collapsing shut-in periods, if any, and using the cumulative production curve for DCA to retain solution objectivity; performing RTA to gauge pressure/rate coherence and system's linearity; and using CRM to establish injector-producer connectivity.

Dynamic reservoir monitoring using seismic data is now a common practice, but when BP North Sea first embarked on this in 1992 using streamer data over Magnus streamer, it was very much stepping into the unknown, with a hope of meeting our pioneering objective of monitoring a significant pressure signal; and if successful, understand what levels of change we could monitor. This was followed up in 1995 with the first permanent array over Foinaven (FARM - Foinaven Active Reservoir Monitoring) which acquired a monitor survey in 1998. A streamer survey soon followed in 1999 which matched the existing 3D of 1993 and resulted in the first large at scale 4D project to investigate. After those initial experiments, no one could have envisaged the level to which the industry has now applied the technology. Since that time BP has acquired over 100 4D monitor surveys over a variety of fields in the North Sea. The 4D experience covers a wide variety of geological settings, from a hard concrete like sea bottom at Clair, to a relatively soft sea bottom at Valhall, from flat sea floor to dipping (Schiehallion) or even rugose (Skarv). We have gained a great deal of experience of both towed streamer and OBS 4D, in some areas it has worked particularly well, and in others, less so, from strong to weak signals, amplitudes and time shifts. In this paper we give an overview of our experiences and where we see the direction of future applications.

Direct combustion of cuttings collected at the rig site can help identifying the presence and assess the variation of organic matter into a drilled rock, with minimum sample preparation and signal processing. This near-real-time data provides key information to optimize and de-risk critical decisions such as selection of sidewall coring points, wireline logging programs and sweet spots identification. The method is based on the isothermal oxidation of the sample, done directly at the wellsite and with field deployable equipment. Extensive lab tests have been done to validate both the measurement and the full workflow. Samples have been measured both with this wellsite dedicated equipment and with advanced lab devices. The results between the different methods have been compared and showed good agreement. The workflow has been applied several times to actual wellsite analysis. The results of one of these cases have been illustrated in this paper, together with the integration of the well site TOC with different datastream (i.e. advanced surface fluid logging and continuous isotope logging).

In 2014 ConocoPhillips (U.K) Ltd. drilled a third development well, a horizontal infill, in the Brodgar gas condensate field (central North Sea) to target a low relief structure 6,000 ft west of the existing production wells. A new deep resistivity tool was successfully used in this well to aid geosteering and mapping of the hydrocarbon envelope. A pilot well was originally proposed to reduce uncertainty around the hydrocarbon-water contact (HWC) and the top structure depth at the target location. However during data acquisition planning, extensive simulations of the response of the deep directional resistivity (DDR) logging-while-drilling (LWD) tool were carried out to evaluate its capability to reduce these uncertainties. The simulations gave confidence in the ability of the DDR tool to: (1) detect the reservoir 50 ft true vertical depth (TVD) away before wellbore arrives at top reservoir; and (2) effectively map the top and base of the entire reservoir zone. The decision was made to drop the pilot well and apply this new technology to mitigate the risks and meet the well plan and production objectives. This decision was supported by detailed reservoir simulation work and uncertainty modelling. The tool response showed the range of hydrocarbon column height upon landing at the initial target location to be between 70 and 110 ft (mid case predrill simulations predicted a column of 104 ft). Due to mechanical issues, this initial wellbore had to be abandoned and sidetracked at the 13 3/8-in shoe. As the sidetrack was a twin of the abandoned hole, the DDR LWD tool was not required for landing the sidetrack but was used for geosteering the horizontal section. The tool provided a real-time resistivity profile that could be interpreted up to 80 ft above and below the wellbore resulting in an accurate “map” of the hydrocarbon envelope. The tool has helped to significantly reduce uncertainty on top structure depth and on water encroachment behaviour, leading to re-interpretation of the seismic, static, and dynamic models. For ConocoPhillips (U.K) Ltd. this case study has demonstrated the value of applying new technology to reduce subsurface uncertainties and eliminate unnecessary well cost.

The Algerian offshore area is located in the western mediterranean sea, East of alboran basin, and south of algero provencal basin. In geological perspective, it covers the area from the narrow continental shelf to the deep basin, water depth range from 0-2800m. Prospectivity is primarily associated with pre-messinian deposits, in addition to Pliocene. The seismic data consists mainly of 2D surveys, with relatively coarse coverage in addition to gravity and magnetic. The 2D seismic coverage acquired in 2011 (5000km) covers the main deep water area. The evaluation of the 2D seismic data has highlighted a number of significant leads with different sizes. They are related to different kind of traps (anticlines, faulted and tilted blocks, …). Only one deep well (4496.5m) and two core drills have been drilled. The onshore geological map reveals the extension toward the offshore of the Chelif basin. The petroleum potential of this onshore basin is proven since the 1940’s with the discoveries of Ain Zeft and Tliouanet oil fields. Reservoirs are expected to consist of sandstones related to Miocene, in addition to the Oligocene (Numidian flyshs) that can be found in the eastern part. The hydrocarbon potential interest in the eastern part could be enhanced by the positive discoveries in the Sicilian channel and also by the proven petroleum system of the Numidian in the onshore part of Tunisia and Algeria (Ain Regada).

Mariner is a large heavy oil discovery in block UK-9/11, located 320 km north east of Aberdeen. The execution and development of the project will be from Statoil's new Aberdeen office. The discovery contains 1–2 Billion Barrels of Oil in Place in two reservoirs (Maureen and Heimdal). 19 appraisal wells have been drilled. The oil viscosities are 67 cp (Maureen) to 508 cp (Heimdal) at reservoir conditions. Production start is in February 2017. The reservoir development is based on use of re-injected produced water. ESP pumps are used for artificial lift. In total 100 wells are planned including multilateral slanted wells and horizontal wells. Two drilling rigs and one work-over rig will be active in parallel the first 4 years. Challenges to be met are related to high oil viscosity which gives early water breakthrough and mapping of remobilized Heimdal channel sands. The available seismic only allows for a stochastic Heimdal reservoir model. A full field broadband seismic survey will be available in 2013, applying the newest advances in technology to aim at better imaging the Heimdal sands. Current development strategy for the Heimdal reservoir is pattern drilling using an inverted 9-spot pattern. The work going forward will focus on use of the new seismic data to establish a deterministic reservoir model to be used for well planning. Work is on-going to significantly optimize the Heimdal development. Active geosteering will be important to limit the use of pilot holes and improve Heimdal reservoir sand mapping. The reservoir simulation model is very computer time consuming. Coupled segment models have been constructed that replicates the full field simulation but with significant reduction in simulation time. A polymer flooding study has been initiated to realize the EOR potential.

The Valhall field has been on production since 1982 and produced in excess of 800 mmboe. The primary reservoir is the over-pressured, high porosity and fractured Upper Cretaceous Tor formation. The field compacts during depletion, resulting in subsidence in the overburden. In 2003 a permanent seismic array, LoFS, was installed across the field. The main objective of the system was to support the water flood program. To date15 seismic surveys have been acquired and the LoFS program has proved to deliver valuable information. In monitoring of the Valhall water-flood program we were facing two fundamental technical challenges; poor p-wave seismic quality in part of the field and the presence of very thin dense, zones with pervasive fault induced fracturing. These fractures act as conduits and distribute the water away from the well. Fortunately, the type of seismic recordings achieved using the permanent system are favorable for the use of full waveform inversion, and we have been able to produce velocity models containing much higher resolution than conventional ray-method based tomography. This model supported focusing of primary seismic reflection such that the presence of the reservoir could be interpreted from 4D seismic images, as the noise that still dominated the conventional 3D images appears to be highly repeatable and was reduced in the inherent differencing process.

This paper is concerned with human activities relating to offshore exploration and exploitation that have adverse effects on marine animals. It addresses noise pollution caused by tasks such as piling, drilling, exploration etc. Loud noise produced during offshore operations can seriously affect one of the main senses – hearing. The paper examines sources of noise and methods of mitigating it to tolerable levels. Research is focused on the use of bubble curtains for noise reduction. The main conclusion is that the bubble curtain is a recognised noise reduction/shielding method and its effectiveness is dependent on bubble size and water depth in addition to water temperature, density and salinity.

The economics of small gas field developments in the Southern North Sea away from any existing infrastructure is particularly sensitive to subsurface uncertainties. Applying latest geophysical approaches is a key aspect of obtaining sufficient grip on these parameters and ensuring robust project economics. For the Alpha field, the structural uncertainty due to poor seismic imaging was identified as critical and therefore a dedicated seismic imaging project was undertaken. It involved re-processing the existing seismic data with the latest velocity modeling and imaging technologies, such as Reverse Time Migration. It led to a clear improvement of the seismic character at objective level as well as a more consistent depth image. As a consequence, the expected volume of gas in place increased by 50% and additional reservoir targets were identified, considerably improving the project economics. In addition, a High Definition 3D seismic image of the shallow subsurface was for the first time successfully created over the area to assess any potential geohazards and ensured that the proposed and selected development concept had mitigations against these hazards and their consequences.

The Nukhul reservoirs of Egypt’s Eastern Desert typically have low porosity, low permeability, and relatively heavy oil. Hence, hydraulic fracturing is key to enhancing reservoir producibility, and an understanding of fracture geometry is important to determine reservoir drainage. To measure hydraulic fracture height at the wellbore, shear wave anisotropy data were acquired in casing with an advanced acoustic tool. Hydraulic fracturing post-job pressure matching also provided estimates of fracture geometry. Shear wave anisotropy data confirmed that the Thebes and Rudeis formations acted as fracture barriers and confirmed the fracture confinement in the Nukhul formation, which was the fracturing job objective. Although, overall, the post-fracturing shear wave anisotropy measurement and the post-job pressure matching delivered similar results for fracture height at the borehole, the shear wave anisotropy data showed uneven levels of anisotropy across the fractured reservoir interval, indicating that the fracture might not have as simple a geometrical shape as was modeled by the post-fracturing analysis. Based on wireline data, a newly constructed and calibrated mechanical earth model obtained detailed rock elastic properties and stress profiles. These geomechanical properties defined 26 zones across the reservoir (instead of the initial 6) and were input into the fracturing modeling software. Fracture geometry obtained through this enhanced modeling closely matched the shear wave anisotropy results—the modeled fracture width corresponded to the variations of shear wave anisotropy observed across the fracture height. The fracture was narrower in the upper part of the reservoir and wider in the lower part, with a half-length of 300 ft in the lower part and almost 400 ft in the upper part. In this case study, we demonstrate how full use of available data, application of the latest acoustic technology, and integration of multiple disciplines (acoustics, geomechanics, stimulation) can lead to better fracture geometry description and achievement of greater accuracy in reservoir description.

The Gryphon Field located in block 9/18b of North Sea was discovered in 1987 and originally comprised of a ~200ft thick oil rim under a gas cap with a strong aquifer. It is connected to another nearby field via the gas cap and has been producing since October 1993. One of the biggest challenges in placing future wells is that production has significantly thinned the original thickness of oil column above the oil-water contact (OWC) and the gas-oil contact (GOC) has moved up due to gas movement and production. A methodology has been developed to estimate current water (OWC) and gas (GOC) oil contacts in the field from initial fluid in place, production and rock and fluid properties. The methodology is based on the volume of remaining fluid in the reservoir using material balance techniques and calculation of the fluid contacts assuming the whole reservoir as a single tank, and with best estimates of initial contacts and residual saturations. Here, the contact movements have been calculated versus time. The calculated fluid contacts show a good agreement for two direct measurements of GOCs from two pilot holes. There is a 50 ft difference between OWCs from these two pilot-holes measurements; the calculated OWC is almost the average of these two values - providing confidence in the approach. The calculated fluid contacts were also compared with recently obtained 4D seismic and up to date reservoir simulation model for different producing wells that show a good match. The completion interval of all wells has been mapped versus the contact movements. The results show that in order to increase oil production from the current the wells, gas injection could be increased in a way that takes into account the effects of fluid movement. The wells need to be operated as much as possible at low gas oil ratio that is possible due to strong water drive. It is also shown that the datum of the new infill wells should be at a shallower depth compared to previous wells.

In preparation for a new phase of development of the deep, >8000 psi depleted, high-pressure, high-temperature (HPHT) Shearwater field in the UK Central Graben of the North Sea, the existing well stock had to be prepared to enable slot availability for sidetracking operations. Here techniques and key learnings gained from the slot preparation activities, in particular with respect to the chalk overburden, are described. During the slot preparation activities new data on fracture gradients and the extent of porosity in the chalk was acquired. This information was then integrated with the results gained from the use of state of the art logging tools and unique data acquisition (including chalk hydrocarbon molecular and isotope compositions). In addition, an analysis of overburden time shifts from re-processed 4D seismic data was completed, along with geomechanical modelling work. A new understanding was gained of the effects of reservoir depletion on the chalk, from being a solid uniform tight rock with very low permeability to a more heterogeneous permeable formation with differential reactions to reservoir depletion. The key learnings have been integrated into the ongoing slot recovery operations and future well plans. The overall integrated data allowed a greater understanding of the heterogeneity of the entire chalk section, which has been valuable in considering chalk overburden complexity.