Keith Hawkins

Production-induced stresses from time-lapse time shifts A geomechanics case study from Franklin and Elgin fields

Franklin and Elgin fields were discovered in 1986 and 1991, respectively, within the U.K. North Sea Central Graben blocks 22/30 and 29/5. The producing reservoirs are contained in the Jurassic Fulmar shallow-marine and Pentland fluvial formations at depths of 5100–5600 m subsea. The fields presented significant development challenges both in terms of seismic imaging complexity and being in a state of exceptionally high pressure/high temperature (HPHT). Addressing these challenges meant that production could not commence until 2001.

Addressing anisotropy in 3-D prestack depth migration: A case study from the Southern North Sea

This is a case study of a 3-D anisotropic prestack depth migration (APSDM) of data from Block L10 of the Dutch sector of the North Sea. Producing gas reservoirs in L10 are typical of the area in that they are contained in horst and tilted fault blocks of the Rotliegend Formation. Imaging these fault blocks is made difficult by a complex overburden greatly influenced by salt tectonics. In particular, the overburden includes chalk characterized by fast velocities and a strong vertical velocity gradient.

Geomechanical stresses from 4D time shifts measured around the depleting Franklin and Elgin reservoirs

This paper is a geomechanics case study in which timelapse timeshifts have been accurately measured over the producing HP/HT Franklin and Elgin gas condensate fields then inverted to production-induced stress and strain changes throughout the reservoir, overburden and underburden. The interpretation of the result can be used to constrain the coupled reservoir-geomechanical model with the objective of enhancing its capacity to detect parts of the reservoirs that have not been depleted, explaining casing integrity problems and anticipating potential wellbore instability problems on infill wells.

Estimation of Production Induced Stress Changes From 4D Finite Offset Timeshifts

Summary Significant stress changes are generated when producing reservoirs compact due to large reductions in the reservoir pore-pressure. These stress changes are not confined to the reservoir. The stress and strain is redistributed to the surrounding formations, modifying both velocity and thicknesses in these formations. These changes often manifest themselves as significant timelapse time differences on migrated 4D images. Various authors (Hatchell et al, 2003 and Barkved et al, 2005) have used geomechanical modelling to explain these 4D timeshifts, thereby gaining valuable insight into the behaviour of the whole subsurface around some compacting reservoirs. This has so far been accomplished by assuming a simple relationship between thickness and velocity changes. The modelling is presumably repeated using various updated relationships until a match is obtained with the observed 4D timeshifts. We present an approach in which the 4D time differences are measured on prestack data. Without relying on any assumed relationship between velocity and thickness changes, we use the additional non-zero offset information combined with raytracing and linear least squares inversion techniques to derive the thickness and velocity changes. These resulting velocity and thickness changes combined with density and pore-pressure well data can then be converted to stress and strain changes. The technique should therefore help to close the loop between seismic 4D time differences and geomechanical stress and strain

High resolution pore‐pressure prediction from AVO derived velocities; a North Sea case study

P167 High resolution pore-pressure prediction from AVO derived velocities; a North Sea case study 1 KEITH HAWKINS ANDREW RATCLIFFE GRAHAM ROBERTS & DAVE WENT. Veritas DGC Crompton Way Manor Royal Estate Crawley West Sussex RH10 9QN UK. Abstract We apply a practical approach to pore-pressure and fracture pressure prediction from seismic velocities derived from amplitude variation with offset (AVO) information. The emphasis is placed on maximising both temporal and lateral resolution of the pressure estimates. Besides assisting exploration well planning improved resolution may be able to define local pressure variations within and around a reservoir that may assist the planning

An integrated geoscience approach to reservoir imaging using anisotropic pre-SDM.

Summary P-wave anisotropic prestack depth migration (APSDM) can produce a seismic image that is very accurate in depth and space. As a result, unlike isotropic PSDM, it is consistent with well data and provides an ideal input for reservoir characterisation studies. However, this accuracy can only be achieved if correct anisotropy parameters are used. These parameters can not be estimated from seismic data alone. They can only be determined with confidence through analysis of a variety of geoscientific material – borehole data, geological history and seismic interpretation. In this paper, this integrated interpretive approach in combination with anisotropic pre-SDM is shown to produce accurate results on a variety of North Sea reservoirs.

Addressing anisotropy in prestack depth migration: a Southern North Sea case study.

In order to optimise gas production from Rotliegend reservoirs located offshore Holland it is crucial to obtain both accurate imaging and depth control of seismic data. Prestack depth migration is essential to achieve accurate imaging in this demanding geological environment. However, isotropic imaging velocities differ from vertical well velocities due to transverse isotropy. Use of a prestack depth migration algorithm that comprehends anisotropy has the advantage of providing greater imaging accuracy and the required accurate depth control consistent with well depths. This means that additional well information such as the depths of formation tops from highly deviated wells can be used to constrain the model building. The more accurate anisotropic algorithm will only be effective if the anisotropic properties of the geology are known. To determine the anisotropic parameters a calibration of the seismic data with existing well data is required. A case study is presented using data from a producing Rotliegend gas field located in block L10 of the Dutch sector in the North Sea. Using the seismic tie with one of the many wells on the field, anisotropy parameters have been determined. The resulting anisotropy parameters have been verified successfully at two other well locations that have varying complexity of structure.

P-wave VTI anisotropy measurements from long offset data: a case study from West Africa

Summary It has long been recognised that the assumption of hyperbolic normal move-out (NMO), routinely used for horizontal reflector travel time in seismic data processing, breaks down when the offset distance between source and receiver approaches and exceeds the depth of the seismic energy reflector. Early work showed that even for isotropic media, the travel-times are an infinite series that can only be restricted to two terms when offset is less than the depth of the horizon. More recently, vari ous researchers have shown that anisotropy is a further complication to the orderly behaviour of reflector travel times. However, when we can assume vertical transverse isotropic symmetry (VTI), the travel times can be readily expressed in terms of anisotropic parameters. While these developments complicate seismic data processing, they also provide a means of potentially extracting more rock property information from our data - akin to the exploitation of amplitude variation with offset (AVO). It also provides a mean s of extending the accuracy of AVO by improved prediction of reflector times at larger angles. We investigate these benefits by deriving anisotropy parameters from a West African data set that was acquired across a Tertiar y Fan system in ultra deep water using offsets in excess of 6km. Furthermore, we examine the accuracy improvement and practical interpretative benefits in deriving anisotropy parameters when we replace higher order NMO schemes with a more correct imaging scheme; finite offset prestack Kirchhoff migration driven by accurate ray-tracing.

Better Ways to Image North Sea Central Graben Diapirs

The velocity regime of The North Sea is noted for its step like character between lithologic zones, in stark contrast to the gentle velocity gradient of the Gulf of Mexico where conventional DMO performs so well. One of the more pronounced North Sea steps is between the Tertiary and Cretaceous Chalk sequences and in such areas it has been shown that conventional DMO is seriously flawed. It has become quite common practice to attempt to circumvent the DMO’s failings by using various schemes that combine it with zero offset pre-stack time migration. We examine the validity of such schemes, comparing them with the theoretically sound Pre-Stack Depth Migration (PSDM) and a relatively new DMO that is able to comprehend any variations in the vertical velocity profile, HDDMO. It is well known that a vertical velocity variation requires the DMO operator to be three dimensional. For the linear velocity gradient of the Gulf of Mexico, the MZO saddle operator is considered appropriate. In the North Sea, however, the 3D DMO operator cannot be generalized so readily and is more complex. HDDMO computes the true 3D nature of the operator that is required and we illustrate its performance in a velocity environment of a typical Central Graben diapir.

Understanding the interaction between marine geometries and 3‐D imaging methods

Modelling algorithms which can accommodate complex and irregular 3D geometries are used to examine the processed seismic response for various template designs and geological models. For a particular imaging process such as conventional constant velocity 3D DMO, the modelled results can be presented as polar amplitude response plots which show the system directivity pattern over all dips and shooting orientations relative to dip for each crossline bin in a specific marine template.