Lennert D. den Boer

Using Bayesian simulations to predict reservoir thickness under tuning conditions

Mapping reservoir thickness from 3-D seismic data is a difficult task when the seismic response is dominated by tuning effects. Deterministic solutions may be considered when the acoustic properties of the reservoir and the encasing material are nearly constant. When the acoustic properties are highly variable, the dispersion of points observed in the tuning curves precludes a deterministic approach, and a statistical method is preferred. In this study, we apply a recently developed nonlinear Bayesian simulation technique to map the thickness of a reservoir associated with an intrusive rock. In contrast to linear geostatistical techniques such as cokriging, this method handles complex nonlinear relationships between thickness and multiple seismic attributes.

From pore-pressure prediction to reservoir characterization: A combined geomechanics-seismic inversion workflow using trend-kriging techniques in a deepwater basin

To optimize drilling decisions and well planning in overpressured areas, it is essential to carry out pore-pressure predictions before drilling. Knowledge of pore pressure implies knowledge of the effective stress, which is a key input for several geomechanics applications, such as fault slip and fault seal analysis and reservoir compaction studies. It is also a required input for 3D and 4D seismic reservoir characterization. Because the seismic response of shales and sand depends on their compaction history, the effective stress will govern the sedimentary seismic response. This is in contrast to normally pressured regimes, where the depth below mudline (or overburden stress) is typically used to characterize the compaction effect.

Predicting Reservoir Compaction and Casing Deformation in Deepwater Turbidites using a 3D Mechanical Earth Model

Production from deepwater turbidites is made more challenging by geomechanical problems arising from overpressure, reservoir compaction, casing failure, etc. The impact of reservoir compaction on field development is best examined early in the life of the field, when there is an opportunity for proactive planning. The interaction between heterogeneous reservoir layers, well trajectories and stress changes due to depletion is a complex 3D problem; it is best solved using a 3D approach. This paper illustrates the use of a 3D MEM (Mechanical Earth Model) to quantify reservoir compaction, casing failure and surface subsidence for a deepwater Gulf of Mexico turbidite. Reservoir flow simulation data are used to evaluate stress changes, reservoir compaction, casing deformation and surface subsidence resulting from production. Geomechanical hot spots, where reservoir compaction is predicted to be greatest, are identified to allow production strategy to be optimized. Several possible modes of production-induced casing failure are examined. The likelihood of casing failure is then assessed to facilitate development of strategies for either avoiding such risks, or reducing their impact. This work shows the importance of developing a 3D MEM early in field development. In high-porosity, pressurecompartmentalized sandstones, quantification of reservoir compaction is essential for planning the casing and completion integrity through the life of the reservoir. Introduction Many oilfield projects today are challenging because of geomechanical problems arising from overpressure, wellbore instability, reservoir compaction, casing failure, sanding, surface subsidence, fault reactivation, etc. The use of a 3D MEM allows all information related to the geomechanics of drilling and production to be captured, including in-situ stresses, rock failure mechanisms, rock mechanical parameters, geologic structure, stratigraphy and well geometry. Once constructed, this model can be used to identify geomechanical problems and to devise contingency plans for handling them before the well is drilled. The use of a 3D MEM for predicting reservoir compaction from pressure depletion, plus its associated impact on casing deformation and surface subsidence, is demonstrated for a complex turbidite reservoir. Fig. 1 shows the steps involved in building a 3D MEM, while Fig. 2 illustrates the construction of a 3D MEM using well logs and seismic horizons. Fig. 3 shows how the MEM may be updated using data acquired while drilling a well. Fig. 1 Steps involved in constructing a 3D MEM. Fig. 2 Construction of a 3D MEM. Well logs are combined with seismic horizons to build the model.

Integrated 3D reservoir modeling for Permian Khuff gas development in Ghawar Field, Saudi Arabia

Prolific gas production originates from the Permian Khuff carbonate reservoirs in the Ain Dar/Shedgum area of Saudi Arabias giant Ghawar Field. However, well productivity is highly variable due to rapid lateral variations of porosity and permeability, which are mainly controlled by changes in depositional facies and diagenesis.

Well‐constrained seismic estimation of pore pressure with uncertainty

Summary A quantitative predrill prediction of formation pore pressure with uncertainty is needed for safe, cost effective drilling in overpressured areas. This paper describes the use of a 3D probabilistic Mechanical Earth Model (MEM) that combines well data with seismic velocities to predict pore pressure and uncertainty. Application is made to an overpressured area in the Gulf of Mexico. Parameters in the velocity-to-pore-pressure transform are estimated using seismic velocities plus density logs, pressure data, and well velocities obtained by inverting time-depth pairs from checkshots in the area. A prediction of pore pressure and uncertainty is made by sampling the region of parameter space consistent with available well data.

Constructing a Discrete Fracture Network Constrained by Seismic Inversion Data

Rock fractures are of great practical importance to petroleum reservoir engineering because they provide pathways for fluid flow, especially in reservoirs with low matrix permeability, where they constitute the primary flow conduits. Understanding the spatial distribution of natural fracture networks is thus key to optimizing production. The impact of fracture systems on fluid flow patterns can be predicted using discrete fracture network models, which allow not only the 6 independent components of the second-rank permeability tensor to be estimated, but also the 21 independent components of the fully anisotropic fourth-rank elastic stiffness tensor, from which the elastic and seismic properties of the fractured rock medium can be predicted. As they are stochastically generated, discrete fracture network realizations are inherently non-unique. It is thus important to constrain their construction, so as to reduce their range of variability and hence the uncertainty of fractured rock properties derived from them. This paper presents the underlying theory and implementation of a method for constructing a geologically realistic discrete fracture network, constrained by seismic amplitude variation with offset and azimuth data. Several different formulations are described, depending on the type of seismic data and prior geologic information available, and the relative strengths and weaknesses of each approach are compared. Potential applications of the method are numerous, including the prediction of fluid flow, elastic and seismic properties of fractured reservoirs, model-based inversion of seismic amplitude variation with offset and azimuth data, and the optimal placement and orientation of infill wells to maximize production. This article is protected by copyright. All rights reserved

Velocity-density relations for deepwater subsalt Gulf of Mexico shales

Rock physics studies based on incomplete data sets often employ empirical relations such as Gardner’s relation between density and P-wave velocity, or Castagna’s mudrock line between Pand S-wave velocities. However, such relations are inappropriate when they disagree with measured data. In this study, P-wave velocity, S-wave velocity and density data for mudrocks in two vertical subsalt wells in the deepwater Green Canyon area of the Gulf of Mexico are shown to deviate appreciably from these empirical relations. By contrast, a rock physics model based on effective field theory not only gives a good description of the data, but also allows the effective pore aspect ratio to be estimated.

Regional trends in undercompaction and overpressure in the Gulf of Mexico

Summary Shallow water flow and overpressure, arising primarily from rapid sedimentation rates generated by the Mississippi River depocenter, represent major drilling hazards in the deepwater Gulf of Mexico. In this paper, checkshots released by the Minerals Management Service (MMS) for the Gulf of Mexico are inverted for velocity versus depth below mudline, then kriged to populate a 3D Mechanical Earth Model (MEM) with both velocity and expected uncertainty. The 3D velocity cube thus obtained is used to infer regional variations in overpressure and undercompaction of shallow sediments.