The anisotropic mechanical characteristics of layered rocks under numerical simulation

Layered rocks pose the challenge of wellbore stability in drilling engineering because of the anisotropic mechanical properties caused by the distinct weak planes. To understand the significant anisotropy of layered rocks in real formation condition, true triaxial compression tests are conducted by numerical simulation in this study. It is revealed that the mechanical responses of layered rocks are either controlled by the rock matrix or dominated by the weak plane and exhibit three different types associated with the orientations of the weak plane (including the dip direction α and dip angle β). When the orientations of the weak plane are α = 0°–90° and β = 0°, 60°–90°, the failure and strength properties of layered rocks depend entirely on the rock matrix, classified to the first type. Whereas the layered rocks with angle α ≤ 45° and β = 15°–45° fail by slipping failure along the weak plane, the relationship curves of rock strength versus the intermediate principal stress (σ2) are downward convex parabolas. In the last type, the mechanical behaviors of layered rocks with α > 45° and β = 15°–45°, involved in the changes of failure mode and the strength curve, are complex. Besides, the limitation of the simulation is discussed, and further studies on layered rocks are essential.

Numerical Assessment of the Hybrid Approach for Simulating Three-Dimensional Flow and Advective Transport in Fractured Rocks

This study presents a hybrid approach for simulating flow and advective transport dynamics in fractured rocks. The developed hybrid domain (HD) model uses the two-dimensional (2D) triangular mesh for fractures and tetrahedral mesh for the three-dimensional (3D) rock matrix in a simulation domain and allows the system of equations to be solved simultaneously. This study also illustrates the HD model with two numerical cases that focus on the flow and advective transport between the fractures and rock matrix. The quantitative assessments are conducted by comparing the HD results with those obtained from the discrete fracture network (DFN) and equivalent continuum porous medium (ECPM) models. Results show that the HD model reproduces the head solutions obtained from the ECPM model in the simulation domain and heads from the DFN model in the fractures in the first case. The particle tracking results show that the mean particle velocity in the HD model can be 7.62 times higher than that obtained from the ECPM mode. In addition, the developed HD model enables detailed calculations of the fluxes at intersections between fractures and cylinder objects in the case and obtains relatively accurate flux along the intersections. The solutions are the key factors to evaluate the sources of contaminant released from the disposal facility.

Acidizing Workflow for Optimized Well Performance in Zhdanov and Lam Oil Fields Offshore Caspian Sea

Successful sandstone matrix stimulation treatments require addressing complex mineralogy, correctly identifying formation damage, selecting the best stimulation fluids, and placing these fluids correctly. The objective of this paper is to demonstrate a workflow considering laboratory testing, advanced software modeling including acid and diverter fluid efficiency calibration using field experimental data, field execution, and relevant case studies in two oil fields located in the Cheleken block, offshore Caspian Sea. Implementation of the workflow has led to positive results. Matrix acidizing was selected as the primary method for restoring production of the oil wells drilled into sandstone reservoirs due to the reservoir characteristics. Deep Zhdanov wells and shallower Lam wells possess ~15 and ~250 md permeability and ~90 and ~50°C static reservoir temperature, respectively. The target rock mineralogy in both fields predominantly consists of quartz, chlorite, and carbonate minerals. Fluids selection, stimulation design and job execution followed the above mentioned workflow. Treatment modeling considered calibration factors derived from field testing and incorporated several acid and diverter systems. A mix of bullhead and coiled tubing placed treatments were employed. The first step of the workflow considered characterization of the rock mineralogy and selection of the best-fit treatment fluids. Rock dissolution and X-ray diffraction (XRD) tests were run to develop the optimum formulations for the treatment conditions. Further, the results of the laboratory testing were incorporated into the advanced matrix acidizing simulator to model and optimize the treatment schedules. The recently developed matrix stimulation software incorporates geochemical, thermal, and placement simulations calibrated with experimental data. Offset well stimulation treatment pressure match was done by calibrating the acid and diverter fluid efficiency, and those calibrated values were considered for design simulations for the following acid treatments. In this paper, the term "acid efficiency" is defined as a measure of the relative rate at which the acid can penetrate when it flows in the rock matrix as a function of matrix porosity and the overall acid reactivity. The term "diverter efficiency" is defined as a measure of the viscosity developed by a given diverter when it flows in the rock matrix. Such a calibration method accounts for the actual reservoir large-scale acid-rock reaction kinetics. Finally, diagnostic tests and main acid treatments were executed that enabled achieving the desired levels of skin reduction, reservoir placement, zone coverage, and hydrocarbon production rates. Several acid stimulation operations were conducted including three cases in which a low-temperature well with carbonate damage needed repeated acidizing and two additional cases that involved wells with deep, hot, and clay-rich pay zones. Several fluid schedules were applied including foam diversion technique. The above approach uses a unique method of acid efficiency calibration using field experimental data. It requires good knowledge of reservoir rock mineralogy, porosity, and permeability profiles in the zones of interest. Pretreatment skin is calibrated using production data prior to acid efficiency calibration based on matching the actual treatment pressures. The pressure behavior observed during the following treatments closely matched the design pressures confirming applicability of the approach.

Simulation of the Infiltration of Fractured Rock in the Unsaturated Zone

We study infiltration of rainwater into fractured rock and the accompanying capillary exchange processes between fractures and matrix, hereafter referred to as fracture–matrix transfer (FMT). Its influence on the velocity of the wetting front for uniform and variable aperture fractures is of prime interest because it determines the penetration depth of infiltration pulses. FMT is modelled explicitly in a discrete fracture and matrix (DFM) framework realised using a hybrid finite element–finite volume discretisation with internal boundaries. The latter separate the fracture mesh from the rock matrix mesh with the benefit that the flow that occurs within the minute fracture subvolume can be tracked with great accuracy. A local interface solver deals with the transient nonlinear aspects of FMT, including spontaneous imbibition of the rock matrix. Two- and three-dimensional heuristic test cases are used to illustrate how FMT affects infiltration. For the investigated scenario, we find that—beyond a critical fracture aperture around 5–10-mm—infiltration rate is no longer affected by FMT. Fracture aperture variations promote in-fracture-plane fingering, with counter-current flow of water (downward) and air (upward). Fracture flow interacts with FMT in a complex fashion. For systems with a small fracture porosity (≤0.01%), our results suggest that intense, hour-long rainfall events can give rise to tens-of-meter-deep infiltration, depending on fracture/matrix properties and initial saturation of the fractured rock mass.

The Role of Rock Matrix Permeability in Controlling Hydraulic Fracturing in Sandstones

A concomitant effect of a hydraulic fracturing experimenting is frequently fluid permeation into the rock matrix, with the injected fluid permeating through the porous rock matrix (leak-off) rather than contributing to the buildup of borehole pressure, thereby slowing down or impeding the hydro-fracturing process. Different parameters, such as low fluid viscosity, low injection rate and high rock permeability, contribute to fluid permeation. This effect is particularly prominent in highly permeable materials, therefore, making sleeve fracturing tests (where an internal jacket separates the injected fluid in the borehole from the porous rock matrix) necessary to generate hydraulic fractures. The side effect, however, is an increase in pressure breakdown, which results in higher volume of injected fluid and in higher seismic activity. To better understand this phenomenon, we report data from a new comparative study from a suite of micro-hydraulic fracturing experiments on highly permeable and on low-permeability rock samples. Experiments were conducted in both sleeve fracture and direct fluid fracture modes using two different injection rates. Consistent with previous studies, our results show that hydraulic fracturing occurred only with low permeation, either due to the intrinsic low permeability or due to the presence of an inner silicon rubber sleeve. In particular, due to the presence of quasi-impermeable inner sleeve or borehole skin in the sleeve fracturing experiment, fracturing occurs, with the breakdown pressure supporting the linear elastic approach considering poroelastic effects, therefore, with low stress drop and consequently low microseismicity. Rock matrix permeability also controls the presence of precursory Acoustic Emission activity, as this is linked to the infiltration of fluids and consequent expansion of the pore space. Finally, permeability is shown to mainly control fracturing speed, because the permeation of fluid into the newly created fracture via the highly permeable rock matrix slows down its full development. The application of these results to the field may help to reduce induced seismicity and to conduct well stimulation in a more efficient way.