Tuesday, July 23, 2019

Seismic Tools for Reservoir Management

Reservoir engineers,geophysicists, geologist and managers agree that the 3D seismic technique can shed light on reservoir structure. But there's more to seismic than faults and layers: with the right handling, seismic data can predict rock and fluid properties across the whole field. Here's a look at some of the powerful probes in the seismic toolbox- inversion, AVO, 3D visualization and time-lapse surveys. 

Oil and gas companies large and small are relying on 3D seismic data to better delieate fields and identify new reserves. Operating companies have quantified and documented the value a 3D survey can add to an exploration or development project, compared to 2D survey. These testimonials describe the key role seismic images play in revealing reservoir locations and structures and the importance of using the information early in the life of a field to derive maximum benefit. 

But some companies are asking more of their 3D seismic surveys, demanding knowledge beyond- in fact between- reflections, and getting it. A new science of reservoir geophysics is emerging to provide this additional information to reservoir engineers. At the heart of the matter are reservoir geophysicist, who rely on high-quality 3D surveys- available through advances in acquisition, processing and interpretation techniques - for complete volume coverage of the reservoir. High-resolution borehole seismic surveys help fuse the surface seismic with log and core data to allow log properties such as lithology, porosity and fluid type to be mapped field-wide. With this more complete understanding of the reservoir, production engineers can optimize development and recover additional reserves. This article reviews case studies of four techniques that show promise- inversion, amplitude variation with offset (AVO), 3D visualization and time-lapse monitoring. 


Inversion is one of the foundations upon which reservoir geophysicist are building tools to make seismic information more useful to engineers. Inversion is so named because it acts as the inverse of forward modeling. Forward modeling takes an earth model of layers with densities and velocities, combines this with a seismic pulse, and turns out a realistic seismic trace- usually called a synthetic. Inversion takes a real seismic trace, removes the seismic pulse, and delivers an earth model of acoustic impedance (AI) , or density times velocity, at the trace location. Seismic inversion can be posed as a problem of obtaining an earth model for which the synthetic best fits the observed data. 

The simplest earth models contain layers with densities and compressional velocities, but more elaborate inversions yield models with shear velocities as well. Ideally, inversions combine surface seismic, vertical seismic profile (VSP), sonic and density log data. 

The main use of inversion for reservoir management comes through log-property mapping: the seismically derived AI values are tested for correlation with logs at the well location- porosity , lithology , water saturation, or any attribute that can be found to correlate. These log properties are then extrapolated throughout the inverted 3D seismic volume using the lateral variation of seismically derived AI to guide the process. 

Adequately processed seismic data are a must for inversion, but the optimum processing required to prepare data for inversion is the subject of much debate, as is the optimal inversion calculation itself. Numerous processing chains have been developed. A workshop was held recently to define the ultimate processing scheme, but to the surprise of the participants, no one method proved best. The trait that sets inversion apart from the standard processing chain for structural interpretation is the need for preservation of true relative amplitudes. Changes in trace amplitude from one location to another may reveal porosity or other formation property variations, but these amplitude changes are subtle and may be obliterated by conventional processing.

Inversion can be performed before or after the seismic traces have been stacked- summed to create a single trace at a central location- but care must be taken to ensure that stacking does not alter amplitudes. In some cases, such as regions where seismic reflection amplitudes vary with angle of incidence at the reflector, stacking does not preserve amplitudes, and inversion must be performed prestack. Only examples of poststack inversion results are presented in this article. 

The simplest inversion scheme derives relative acoustic impedance changes for one seismic trace by computing a cumulative sum of the amplitudes in the trace. The gradual trend of increasing AI with depth- invisible to seismic waves- is taken from density and cumulative sonic travel times, and added to the relative AI results.

Porosity Mapping in the Hod Field Chalks

Amoco Norway in Stavanger has drawn upon seismic inversion followed by porosity mapping as an aid to managing the development of the Hod field, the southern-most in the trend of chalk oil fields in the Norwegian sector of the North Sea. The two separate oil-filled anticlinal structures in the field - West and East Hod- were discovered in 1974 and 1977, respectively. However, reservoir uncertainties were not resolved by appraisal drilling, and marginal economics delayed production until 1990. Total estimated original reserves for the field are 66.9 million barrels of oil equivalent (BOE) , of which 94% are attributed to East Hod. An unmanned production platform is tied to the Valhall facilities to the north.

The primary reservoir interval at East Hod comprises allocthonous- reworked and redeposited- chalks of the Tor formation. The 2/11-A2 well encounters a prime chalk reservoir section, with 90 m [295 ft] of Tor formation showing porosities of up to 50%. Although East Hod is associated with a pronounced anticlinal closure, oil is trapped not only structurally, but also stratigraphically. Moveable oil has been observed below the established spillpoint, with reservoir distribution controlled by a combination of depositional, structural and diagenetic factors. The complex interplay between these factors results in a highly variable chalk reservoir. 

The top chalk surface represents an erosional unconformity that exposes a variety of chalk types from the Ekofisk, Tor and Hod formations to the overlying Paleocene shale seal. Well data show that chalks contributing to the top chalk seismic event have porosities ranging from 20 to 50% , with impedances ranging from 30,000 ft/sec x g/cm3 to 10,000 ft/sec x g/cm3. The high-quality reservoir rocks exhibit a decrease in acoustic impedance compared to the relatively uniform acoustic impedance of the overlying shale, while nonreservoir chalks show an increase. Therefore the acoustic properties of the chalk exert the primary influence on the amplitude of seismic reflections, making it possible to develop an effective method for mapping the reservoir extent and quality from inverted posstack seismic data.

Various 2D and 3D seismic inversion and porosity mapping techniques have been successfully applied in the area. Because of the combination of the great range in chalk impedance, and its predictable dependance on porosity, the results of most inversion techniques establish similar porosity trends, with the differences to be found in small details and absolute porosity values. 

The first 3D porosity mapping at Hod field was carried out using the Log-Property Mapping modole of the RM Reservoir Modeling system. Vertical well 2/11-3, with its excellent tie to the surface seismic data, was used as the key well to calibrate the inversion. The other wells also provided input to the low-frequency AI model and calibration of AI to porosity. 

This mapping supports the presence of a zone of high porosity beyond the limit of the East Hod structural closure.Subsequent drilling in this area has confirmed the inversion predictions of commercial porosity, and a horizontal producing well is currently draining the area which now represents a proven extension of the Hod field.

An ever increasing functionality and quality of applications are available for this type of reservoir characterization. An example of a significant refinement to the process used in the Hod field area is a scheme called space-adaptive wavelet processing. Applied as a precursor to inversion, this process integrates information from many wells to ensure that seismic data with a common, broadband, zero-phase wavelet are input to the inversion. The resulting improvement in the resolution of the inversion and subsequent interpretation have allowed porosity mapping from seismic to become a standard part of the chalk reservoir management process, and a primary means of identifying and quantifying the potential for extensions to the field or separate accumulations nearby.

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