Practical Issues of 4D Seismic Reservoir Monitoring: What an Engineer Needs to Know
- D.E. Lumley (Chevron Petroleum Technology Co.) | R.A. Behrens (Chevron Petroleum Technology Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- December 1998
- Document Type
- Journal Paper
- 528 - 538
- 1998. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 5.4.2 Gas Injection Methods, 5.1 Reservoir Characterisation, 4.3.4 Scale, 1.14 Casing and Cementing, 7.2.1 Risk, Uncertainty and Risk Assessment, 5.1.7 Seismic Processing and Interpretation, 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.5.3 Scaling Methods, 1.6 Drilling Operations, 5.4.6 Thermal Methods, 3.3 Well & Reservoir Surveillance and Monitoring, 3.3.2 Borehole Imaging and Wellbore Seismic, 1.6.9 Coring, Fishing, 5.1.2 Faults and Fracture Characterisation, 5.1.6 Near-Well and Vertical Seismic Profiles, 5.6.10 Seismic (Four Dimensional) Monitoring, 5.6.1 Open hole/cased hole log analysis, 5.1.5 Geologic Modeling, 4.1.2 Separation and Treating, 5.5.8 History Matching, 2.4.3 Sand/Solids Control, 1.8 Formation Damage, 4.1.5 Processing Equipment, 5.1.8 Seismic Modelling, 5.5.2 Construction of Static Models, 1.2.3 Rock properties, 5.4 Enhanced Recovery, 5.6.6 Cross-well Tomography, 5.4.1 Waterflooding, 5.1.1 Exploration, Development, Structural Geology, 3 Production and Well Operations, 5.2 Reservoir Fluid Dynamics, 5.1.9 Four-Dimensional and Four-Component Seismic
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Time-lapse three-dimensional (3D) seismic, which geophysicists often abbreviate to four-dimensional (4D) seismic, has the ability to image fluid flow in the interwell volume by repeating a series of 3D seismic surveys over time. Four-dimensional seismic shows great potential in reservoir monitoring and management for mapping bypassed oil, monitoring fluid contacts and injection fronts, identifying pressure compartmentalization, and characterizing the fluid-flow properties of faults. However, many practical issues can complicate the simple underlying concept of a 4D project. We address these practical issues from the perspective of a reservoir engineer on an asset team by asking a series of practical questions and discussing them with examples from several of Chevron's ongoing 4D projects.
We discuss feasibility tests, technical risks, and the cost of doing 4D seismic. A 4D project must pass three critical tests to be successful in a particular reservoir: Is the reservoir rock highly compressible and porous? Is there a large compressibility contrast and sufficient saturation changes over time between the monitored fluids? and Is it possible to obtain high-quality 3D seismic data in the area with clear reservoir images and highly repeatable seismic acquisition? The risks associated with a 4D seismic project include false anomalies caused by artifacts of time-lapse seismic acquisition and processing and the ambiguity of seismic interpretation in trying to relate time-lapse changes in seismic data to changes in saturation, pressure, temperature, or rock properties. The cost of 4D seismic can be viewed as a surcharge on anticipated well work and expressed as a cost ratio (seismic/wells), which our analysis shows ranges from 5 to 35% on land, 10 to 50% on marine shelf properties, and 5 to 10% in deepwater fields. Four-dimensional seismic is an emerging technology that holds great promise for reservoir management applications, but the significant practical issues involved can make or break any 4D project and need to be carefully considered.
Four-dimensional seismic reservoir monitoring is the process of repeating a series of 3D seismic surveys over a producing reservoir in time-lapse mode. It has a potentially huge impact in reservoir management because it is the first technique that may allow engineers to image dynamic reservoir processes1 such as fluid movement,2 pressure build-up,3 and heat flow4,5 in a reservoir in a true volumetric sense. However, we demonstrate that practical operational issues easily can complicate the simple underlying concept. These issues include requiring the right mix of business drivers, a favorable technical risk assessment and feasibility study, a highly repeatable seismic acquisition survey design, careful high-resolution amplitude-preserved seismic data processing, and an ultimate reconciliation of 4D seismic images with independent reservoir borehole data and history-matched flow simulations. The practical issues associated with 4D seismic suggest that it is not a panacea. Four-dimensional seismic is an exciting new emerging technology that requires careful analysis and integration with traditional engineering data and workflows to be successful.
Our objective in this paper is to provide an overview of the 4D seismic method and illuminate the practical issues important to an asset team reservoir engineer. For this reason, we do not present a comprehensive case study of a single 4D project here, but instead draw examples from several Chevron 4D projects to illustrate each of our points. We have structured this paper as a series of questions an engineer should ask before undertaking any 4D seismic project: What is 4D seismic? What can 4D seismic do for me? Will 4D seismic work in my reservoir? What are the risks with 4D seismic? What does 4D seismic cost? We answer these questions, highlight important issues, and offer lessons learned, rules of thumb, and general words of advice.
What Is 4D Seismic?
To describe the basic concepts underlying 4D seismic, we briefly review the seismic method in general6 and then consider the advantages of the time-lapse aspect of 4D seismic. In a single 3D seismic survey, seismic sources (dynamite, airguns, vibrators, etc.) generate seismic waves at or near the earth's surface. These source waves reflect off subsurface seismic impedance contrasts that are a function of rock and fluid compressibility, shear modulus, and bulk density. Arrays of receivers (geophones or hydrophones) record the reflected seismic waves as they arrive back at the earth's surface. Applying a wave-equation-imaging algorithm7 to the recorded wavefield creates a 3D seismic image of the reservoir rock and fluid property contrasts that are responsible for the reflections. Four-dimensional seismic analysis involves simply repeating the 3D seismic surveys, such that the fourth dimension is calendar time,8 to construct and compare seismic images in time-lapse mode to monitor time-varying processes in the subsurface during reservoir production. The term 4D seismic is usually reserved for time-lapse 3D seismic, as opposed to other time-lapse seismic techniques that do not have 3D volumetric coverage [e.g., twodimensional (2D) surface seismic, and the borehole seismic methods of vertical seismic profiling and crosswell seismic9,10].
Four-dimensional seismic has all the traditional reservoir characterization benefits of 3D seismic,11 plus the major additional benefit that fluid-flow features may be imaged directly. To first order, seismic images are sensitive to spatial contrasts in two distinct types of reservoir properties: time-invariant static geology properties such as lithology, porosity, and shale content; and time-varying dynamic fluid-flow properties such as fluid saturation, pore pressure, and temperature. Fig. 1 shows how the seismic impedance of rock samples with varying porosity changes as the pore saturation changes from oil-full to water-swept conditions. Given a single 3D seismic survey, representing a single snapshot in time of the reservoir, the static geology and dynamic fluid-flow contributions to the seismic image couple nonuniquely and are, therefore, difficult to separate unambiguously. For example, it may be impossible to distinguish a fluid contact from a lithologic boundary in a single seismic image, as shown in Frames 1 and 2 of Fig. 2. Examining the difference between time-lapse 3D seismic images (i.e., 4D seismic) allows the time-invariant geologic contributions to cancel, resulting in a direct image of the time-varying changes caused by reservoir fluid flow (Frame 3 of Fig. 2). In this way, the 4D seismic technique has the potential to image reservoirscale changes in fluid saturation, pore pressure, and temperature during production.
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