TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents a new set of rock-drilling fluid interaction tests carried out in the diffusion cell using saline solutions and mineral oil on a Brazilian offshore shale. The diffusion cell was designed to apply hydraulic and chemical gradients through shale samples in order to evaluate shalefluid interaction. The proposed test allows the determination of rock permeability, the coefficient of reflectivity (membrane efficiency) and the ionic diffusion coefficient. These parameters are essential to carry out proper wellbore stability analysis when taking shale-drilling fluid interaction into account. Shale characterization, testing methodology and test results are described. The results showed an average permeability of 46 nD and membrane efficiency less than 2 % for the tested shale.

This paper presents a new set of rock-drilling fluid interaction tests carried out in the diffusion cell using saline solutions and mineral oil on a Brazilian offshore shale. The diffusion cell was designed to apply hydraulic and chemical gradients through shale samples in order to evaluate shale-fluid interaction. The proposed test allows the determination of rock permeability, the coefficient of reflectivity (membrane efficiency) and the ionic diffusion coefficient. These parameters are essential to carry out proper wellbore stability analysis when taking shale-drilling fluid interaction into account. Shale characterization, testing methodology and test results are described. The results showed an average permeability of 46 nD and membrane efficiency less than 2 % for the tested shale. Introduction Drilling through shales has presented serious problems of instability and most of them have been attributed to interaction between this rock and the drilling fluid. Normally, long periods of time are necessary to solve some of these problems and that contributes to raise drilling costs. 10-years old data, [1], indicate that nearly 30 % of the additional costs during drilling operations are caused by wellbore instabilities and from these, almost 90 % occur during drilling through shales. These problems used to consume more than US$ 500 million per year considering the technology available then. Much has been learned since then, and that allowed the successful drilling of highly inclined wells with the use of a new generation of drilling fluids. However, on average, the losses are still quite high and there is much to be done to transform the research results into daily practice. The proper selection of the drilling fluid for a given situation is still an issue to be dealt with in drilling operations. The ideal drilling fluid concerning stability of wells must keep the confining effective stresses around the well high enough to preclude rock failure. This can be achieved by, at least, three distinct manners. Firstly, by avoiding pore pressure increase due to fluid penetration through the use of high-entry pressure fluids, i.e., oil-based-like type of fluid. Secondly, by playing with the osmotic effects caused by water-based, saline fluids. Thirdly, by the use of invert-emulsion fluids, [2], that combine the two previous mechanisms. The pore pressure control, achieved through osmotic effects, can be exercised understanding the concepts and quantifying the processes of mass transport due to hydraulic and chemical gradients. In low permeability rocks, such as shales, these gradients induce changes in pore pressures due to effects of hydraulic and ionic diffusion and osmotic effects that can change with rock capability to restrict ion flux through the formation. This is the most studied topic related to shale-drilling fluid interaction. In spite of the importance of drilling fluid-shale interaction, few experimental studies that mimic drilling fluid contact with shale under partial borehole conditions have been developed around the world, [2–7]. At the same time, some of these studies only present qualitative results about the rock-fluid interactions without obtaining the mass transport parameters necessary in wellbore stability analyses. In order to evaluate shale-drilling fluid interactions, new equipment capable to simulate in situ pressure conditions was developed and presented by Muniz et al. (2004) [8]. In this equipment, hydraulic and ionic gradients can be imposed to a shale sample in order to estimate its permeability, the reflection coefficient (membrane efficiency) and the ionic diffusion coefficient. These parameters are used as input in computer programs that take into account physical-chemical interactions to evaluate wellbore stability. The aim of the present paper is to describe the procedures to evaluate the mass transport parameters, i.e., permeability, ion diffusion and membrane efficiency, of shales. Offshore Brazilian shale was used for the tests. Tests and results using the mercury injection technique and scanning electronic microscopy are presented. The reflection coefficients obtained using the computer program FPORO©, described in reference [9], compared well with the values obtained directly from the experiments.

No abstract

A maturing UAE field has multiple stacked oil and gas reservoirs experiencing differential depletion causing unequal increases in vertical and horizontal effective stresses on reservoirs and bounding rock units. The stress variation has resulted from long-term production with some intervals experiencing a reduction of reservoir pressure of more than 2,000 psi. Moreover, reservoir compaction and pore collapse become more serious with the increasing stress acting on the rock framework—particularly upon reaching a critical pressure value. Laboratory measurements of rock compressibility under simulated in-situ stress conditions were conducted to quantify production-induced changes and evaluate pore volume and permeability reduction as a function of reservoir pressure. Furthermore, integration of lab measurements and logs (well and seismic) is driving a geomechanical model covering a broad view of the stacked reservoirs to provide appropriate pore collapse mitigation measures. Pore collapse implications were examined by conducting geomechanical laboratory testing on representative samples—honoring rock heterogeneity through well logs and continuous core measurements and including uniaxial-strain compression (far-field compaction), triaxial compression (near-wellbore compaction), hydrostatic compression (compactant cap), and constant stress path (fixed Ko, far-field compaction). Laboratory data were combined to evaluate shear failure vs. compaction failure in q-p space (i.e., shear stress vs. effective mean stress). Reservoir depletion was monitored continuously from preproduction in-situ stress to planned abandonment conditions for 10 reservoir sections with varying porosity. Testing conducted on the reservoir intervals under study was designed to capture all possible depletion scenarios during the potential life of the reservoir. This study thus improves the appreciation of the mechanics of rock compressibility—in connection with its strong dependence on reservoir stress path (e.g., hydrostatic compression or uniaxial strain compression) and depletion rate—for addressing problems such as rapid loss in permeability, generation of fines, surface subsidence, wellbore instability, casing deformation, and loss of caprock containment. This paper starts by outlining core analysis workflows that can adequately assess potential changes to reservoirs during depletion, highlighting a workflow for constructing a 3D geomechanical model. The results showed that rock with porosity >25% has a propensity for accelerated compaction prior to reaching abandonment pressure. These results were then integrated with reservoir simulation models for long-term field management, which is part of an ongoing modeling effort. The integration of laboratory testing with seismic-driven geomechanical modeling helps predict the impact of production-induced stress changes on field performance. This will, therefore, aid operators in making life-of-reservoir decisions that relate to compaction mitigation and formation stimulation.

Following decades of production from multiple separated stacked reservoirs, a maturing field has undergone many subsurface activities, such as drilling, oil and gas production, and injection of water and gas for reservoir stimulation. Considering the long-term field development plan, one reservoir will be depleted by 5,000 psi after 20 years. Such high levels of depletion can produce severe reservoir compaction and pore collapse, leading to a rapid loss in permeability, generation of fines (byproducts of pore collapse and/or grain crushing), subsidence, wellbore instability, damage to well completion integrity, and loss of caprock containment. An extensive rock mechanics laboratory study was conducted to assess the possibility of pore collapse and prevent and mitigate risks proactively from adverse reservoir compaction. During depletion, the reduction in reservoir pressure results in unequal increases in vertical and horizontal effective stresses and thus an overall increase in the effective mean and shear stresses on the reservoir. At reservoir pressures below a critical value (obtained via laboratory testing or post-failure field analysis), the reservoir may compact at accelerated rates. To fulfill the objective of this study, a series of tests were designed to probe all possible depletion scenarios. Rock failure parameters were evaluated through a sequence of tests of carefully selected, representative samples. Failure envelopes defining shear (dilatant) and compaction ("cap") for compactable sediments are often strongly nonlinear. For field applications, it is useful to provide a visualization of the preproduction-state in-situ stress conditions and the possible stress path trajectories of the reservoir (from triaxial Ko=0 to hydrostatic Ko=1) as a function of reservoir depletion. Using this display, the level of depletion resulting from accelerated compaction was identified through laboratory testing. Tests conducted for assessment of reservoir compaction are: uniaxial- strain compression (far-field compaction), triaxial compression (near-wellbore compaction), hydrostatic (define the compactant cap), and constant stress-path (fixed Ko, far-field compaction). The rock units evaluated were exceptionally heterogeneous, with tensile strength and unconfined compressive strength ranging from 323 to 2,987 psi and 2,944 to 34,481 psi, respectively. Testing conducted on the reservoir intervals were designed to capture all possible depletion scenarios during the potential life of the reservoir. Results have shown that rock with porosity >26% have a propensity for accelerated compaction prior to plan abandonment pressures. Further, accelerated compaction does not occur for rock with porosities below 25%, even following extreme reservoir depletion of 5,000 psi. This paper outlines core analysis workflows that can adequately assess potential changes to reservoirs during depletion—from preproduction conditions to abandonment. Further, the paper highlights the importance of understanding rock heterogeneity prior to initiating any core analysis program.