BP Norge (Norway)

Abstract Many wells around the world suffer from compromised integrity in the form of leaking annular cement sheaths. Fixing leaking annular cement barriers is generally a labor intensive and costly proposition, particularly in offshore environments. If the leaking cement sheath is opposite a creeping shale or salt formation, there is a possibility of such a mobile formation "healing" the voids, cracks and annuli in the cement sheath and re-establishing annular barrier integrity. Such "healing" can be relatively easily achieved using heaters deployed in the wellbore without the need to create annular access. Large scale "shale-as-a-barrier (SAAB)" rock mechanics tests were carried out in the investigation reported here using a custom-built temperature-controlled triaxial frame to test shale core samples with an inner borehole. This borehole contained a simulated casing string and an annular cement sheath, which could be compromised either by using rubble-ized cement in the annulus or using repeated pressure cycles in the wellbore to attempt to create a micro-annulus at the casing-to-cement interface. The integrity of the annular barrier (or lack thereof) was probed throughout the test using pressure pulse decay experiments, and at the end of the test by breakthrough testing. The creep rate in the North Sea Lark shale was beneficially manipulated using elevated shale sample temperature. In the experiments with rubble-ized cement, it was found that thermally stimulated shale creep can plug the cracks, fractures and voids present within the cement material effectively to form a barrier. In the experiments with intact cement subjected to casing pressure cycles, evidence was obtained that thermally stimulated creep can support the annular cement barrier. The effect of elevated temperature, representing the effect of the deployment of a heater in an actual well setting, proved crucial to magnify and accelerate the creep phenomenon responsible for plugging the flow paths in the compromised cement. With many hundreds of thousands of wells around the work already leaking (or potentially leaking at some point in the future) and/or showing casing pressure at surface because of compromised annular cement barriers, it is important to find (cost-)effective long term remedial solutions. For wells intersection shale or salt formations that either creep at in-situ stress and temperature conditions, or can be induced to creep through thermal stimulation, the remediation using such creep to restore and improve the cement barrier is simple, practical (can be deployed with existing downhole heaters), cost-effective, and is expected to last for an indefinite timeframe. It thereby has the potential to revolutionize P&A operations on wells with compromised integrity.

Abstract BP-Norge AS operates the Valhall Field in Norway and relies on multi-zone water injection for reservoir management and control of unwanted water production for Valhall wells. A produced water shutoff method in this field is necessary, and equipment must be capable of maintaining integrity at differential pressures of 10,000 psi during prop-fracture stimulation of the individual zones in the oil-producing wells. The operator wanted to find a new completions solution that would enable long horizontal reservoir sections to be completed and stimulated with the capability to shut-off unwanted water at a later time during well life. Swellable elastomer packers (SEPs) were suggested to the operator as a possible method for zonal isolation. Unfortunately, three attempts to qualify the currently available SEPs to the 10,000-psi differential pressure (DP) for Valhall were all unsuccessful; therefore, the decision was made to try a new design that used an innovative mechanical end-ring system. This configuration uses a solids-laden oil-based mud (OBM) to expand the element installed on the outer surface of the basepipe that forms part of the reservoir liner. This eliminated the need to spot dedicated swelling fluid. The changed configuration represented a significant step change in the design methodology of SEPs. The new design not only enabled the reduction of element length and packer OD, but it also could withstand the high DP ratings as well as increased the DP ratings of long SEPs. The new configuration required qualification testing, and this paper presents the case history of the operator's full-scale qualification testing up to 10,000 psi across two 5-meter packers as well as the improvements the new SEPs could offer over previously used equipment and methods. The paper will also discuss the design, other potential applications, and the advantages of the new SEP design. A case history of the first installations of the new SEP worldwide will be presented as well.

ABSTRACTThe frequent time‐lapse observations from the life of field seismic system across the Valhall field provide a wealth of information. The responses from the production and injection wells can be observed through time‐shift and amplitude changes. These observations can be compared to modelled synthetic seismic responses from a reservoir simulation model of the Valhall Field. The observed differences between the observations and the modelling are used to update and improve the history match of the reservoir model. The uncertainty of the resulting model is reduced and a more confident prediction of future reservoir performance is provided.A workflow is presented to convert the reservoir model to a synthetic seismic response and compare the results to the observed time‐lapse responses for any time range and area of interest. Correlation based match quality factors are calculated to quantify the visual differences. This match quality factor allows us to quantitatively compare alternative reservoir models to help identify the parameters that best match the seismic observations.Three different case studies are shown where this workflow has helped to reduce the uncertainty range associated with specific reservoir parameters. By updating various reservoir model parameters we have been able to improve the match to the observations and thereby improve the overall reservoir model predictability. The examples show positive results in a range of different reservoir modelling issues, which indicates the flexibility of this workflow and the ability to have an impact in most reservoir modelling challenges.

Summary The Valhall field is an overpressured, undersaturated Upper Cretaceous chalk reservoir located in the Norwegian sector of the North Sea. The reservoirs consist of weak chalk. The weak chalk results in significant reservoir compaction, exceeding 10 m in places, and corresponding seafloor subsidence, exceeding 6 m above the center of the field. Previous papers have documented the increasing drilling challenges in the shale overburden at Valhall because of the subsidence. This paper presents the computational-geomechanics technology developed and implemented to assist drilling into the highly depleted and compacted crest from the new water-injection platform at Valhall. The work focuses on handling the stress changes occurring in the overburden above a compacting reservoir and not the more traditional situation associated with depletion-induced fracture-gradient changes in the reservoir itself. The technology is based on a history-matched full-field finite-element-based geomechanics model to calculate stresses, strains, and displacements. The results are exported from the finite-element model (FEM) to a geological modeling software to perform wellbore-stability calculations using BP best practices for prediction of wellbore stability. In this environment, one can also easily use as supporting data 4D seismic from the permanent life-of-field seismic array at Valhall. By calculating the operational mud-weight window over a high risk interval in the overburden, a good correlation to historical nonproductive time (NPT) was found. The methodology is used in detailed well planning where moving the well 50 m in one direction is the difference between problem-free drilling or huge drilling challenges. The paper presents the first application of this technology on a new water injector delivered 60 days ahead of schedule with reduced costs of approximately USD 20 million and with avoidance of a potential "train wreck" that could have cost USD 60 million.

Abstract New completion techniques improving recovery, production rates and reducing cost and complexity are always looked for in the oil and gas industry. This paper is presenting a new concept where 100's of small level 5 laterals can be drilled simultaneously into the formation around a main wellbore. This paper presents the main concept as well as some preliminary results from qualifying the system for service in a high porosity very weak chalk reservoir. The qualification of the system is addressing three main aspects, the ability to jet a 12 meter long and 5–10mm diameter lateral, the ability to produce in high porosity weak chalk without loss of production, and simulation of production that is at least as good as or better than existing technologies like propped fractured horizontal wells, acid fractured horizontal wells and different types of openhole completions with and without liners. The experiments indicate that the system is able to achieve the results we are looking for.

Reservoir simulation is the industry standard for reservoir management that is used in all phases of field development. As the main source of information, prediction and decision-making, the Full Field Models (FFM) is regularly updated to include the latest measurements and interpretations. A typical FFM consists of large number of grid blocks and usually takes hours for each run. This makes comprehensive analysis of the solution space and incorporation of the FFM in smart fields impractical. Surrogate Reservoir Models (SRMs) are introduced as a bridge to make Real-Time Reservoir Management possible. SRMs are replicas of FFM that can run in fractions of a second. They accurately mimic the capabilities of FFM and are used for automatic history matching, real-time optimisation, real-time decision-making and quantification of uncertainties. This paper presents the development of SRM using the state of the art Artificial Intelligence and Data Mining (AID Accepted: November 4, 2008]

Abstract BP's Norway Assets have been recognised as a leading practitioner in the implementation of innovative intelligent energy solutions, what BP calls FIELD OF THE FUTURE technology. The installation in 1999 of a fibre cable, linking BP Norway's headquarters in Stavanger with their offshore operated assets, has been instrumental in putting BP Norway in the vanguard of implementing this new technology and associated work flows. This paper will take a look back over the substantial achievements and benefits that have accrued through the implementation of these technologies and review the experience gained. It will also look forward to the plans BP Norway have for taking their achievements to an even higher level of performance by fully embracing innovative intelligent energy solution concepts in two major projects that come on line in 2010/11. This paper will present case studies of the various enabling and novel technologies installed to date, how these have been integrated within the operating environment, and demonstrate the continuing delivery of value. Examples presented will include: implementation and progressive development of the Advanced Collaborative Environment (ACE) concept;○from an early pilot operations centre,○through the implementation of what is believed to be the World's first 24/7 Onshore Drilling Operations Centre.○to the current generation of operations and support ACE's.introduction and integration of FIELD OF THE FUTURE technology into the assets and how this continues to impact production and plant efficiency;○the first full scale life of field seismic array,○an innovative set of optimisation tools○remote integrated surveillance tools for real time remote monitoring of wells and plant. These tools have not only enhanced collaboration locally, but also enabled effective remote support form BP's Technology Centre and from specialist consultants, resulting in sustained improvement in asset performance.

BP has developed a workflow for quantitatively integrating results from time-lapse seismic surveys into our reservoir simulation models. This is an extension of our “top-down reservoir modeling (TDRM)” philosophy and toolkit that has become BP's standard method for conducting history-matching studies with conventional well data (Williams et al., 2004).

SUMMARY In situ stress monitoring of crustal rocks is desirable as it yields insights into earthquake mechanisms, volcanic eruptions and changes in hydrocarbon reservoirs. Shear wave splitting, induced by stress-controlled cracks in the shallow crust, provides a way to infer this stress. Temporal variations in these observations can be difficult to quantify due to scatter in the data and discontinuous observations. Here we present evidence of temporal variations in shear wave splitting from a continuous time-series with a high occurrence of microseismic events recorded in a borehole. We interpret these observations in terms of stress-controlled cracks and are able to infer changes in stress and, via modelling, suggest the cause of the anisotropy. Possible origins of the temporal variation in per cent anisotropy are tidal or oil-field production processes. Our results suggest that shear wave splitting is a viable probe for inferring changes in crustal stress in cracked rock.

P -to- S converted waves (or C -waves) have been successfully used to image beneath gas clouds in many areas. However, C -waves often suffer from severe diodic effects due to the gas clouds; that is, the C -wave amplitude and traveltime may be different in the forward and reverse shooting directions, giving rise to different C -wave stacking velocities ( diodic V C ) and velocity ratios ( diodic γeff). In some cases, whether a horizon (a geologic target) beneath a gas cloud can be undershot also depends on the shooting directions ( diodic illumination). These effects, compounded with the asymmetric raypath of the C -wave and the uncertainties in the P -wave data due to the gas clouds, will further increase the difficulties and costs of processing C -wave data. In this article, using the 2-D Valhall data as an example, we examine these effects and discuss ways to compensate for them during processing for improving the C -wave imaging. The 2-D Valhall data were acquired in 1996. In the survey area, the overburden layers are highly charged with gas. These gas clouds are not thought to be present in economic quantities, but they attenuate the P -wave energy substantially and reduce the P -wave velocity, inducing dimming and push-down effects on the P -wave data (Figure 1a). Figure 1. (a) The final prestack-migrated P -wave imaging from the vertical geophone of the Valhall data. Note the dimming and push-down effects due to gas clouds. The vertical axis is two-way P -wave time. (b) The initial poststack-migrated image of the C -wave from the in-line horizontal geophone of the Valhall data. The processing involves asymptotic common-conversion-point (ACCP) binning, NMO, DMO, stack, and poststack migration. The vertical axis is two-way C -wave time. The picks shown are examples of P -wave to C -wave …