Borehole measurements are often subject to uncertainty resulting from the effects of mud-filtrate invasion. Accurate interpretation of these measurements relies on properly understanding and incorporating mud-filtrate invasion effects in the calculation of petrophysical properties. Although attempts to experimentally investigate mud-filtrate invasion and mudcake deposition have been numerous, the majority of published laboratory data are from experiments performed using linear rather than radial geometry, homogeneous rock properties, and water-based (WBM) rather than oil- or synthetic oil-based drilling mud (OBM or SOBM).
We introduce a new experimental method to accurately reproduce conditions in the borehole and near-wellbore region during, and shortly after the drilling process, when the majority of wellbore measurements are acquired. Rather than using a linear-flow apparatus, the experiments are performed using cylindrical rock cores with a hole drilled axially through the center. Radial mud-filtrate invasion takes place while injecting pressurized drilling mud into the hole at the center of the core while the outside of the core is maintained at a lower pressure. During the experiments, the core sample is rapidly and repeatedly scanned using high-resolution X-ray microcomputed tomography (micro-CT), allowing for visualization and quantification of the time-space distribution of mud filtrate and mudcake thickness. Because of the size of the core sample, the developed experimental method allows for accurate evaluation of the influence of various rock properties, such as the presence of spatial heterogeneity and fluid properties, including WBM versus OBM, on the processes of mud-filtrate invasion and mudcake deposition. Results indicate that our experimental procedure reliably captures the interplay between the spatial distributions of fluid properties and rock heterogeneities during the process of mud-filtrate invasion.
Successful in-situ fluid cleanup and sampling operations are commonly driven by a fast and reliable analysis of pressure, rate, and contamination measurements. Currently, techniques such as pressure transient analysis (PTA) and rate transient analysis (RTA) provide important information to quantify reservoir complexity, whereas fluid contamination measurements are overlooked for reservoir characterization purposes. The objective in this paper is to introduce a new interpretation technique to relate fluid contamination measurements with reservoir properties by identifying early- and late-time flow regimes in the derivative plots of reciprocal fluid contamination. Among several applications, this new transient analysis method is effective for improving logging-while-drilling (LWD) fluid sampling operations.
The derivative methods used in PTA and RTA inspired the development of the new fluid contamination interpretation method. Contamination transient analysis (CTA) evaluates transient measurements acquired during mud-filtrate invasion cleanup to infer reservoir geometry. We apply derivative methods to the reciprocal of the time evolution of fluid contamination to identify flow regimes in cases of water-based mud invading either water-or hydrocarbon-saturated formations. LWD operations are considered under a continuous invasion effect, i.e. the fluid cleanup procedure is performed while mud filtrate continues to invade the formation. This constraint brings about a significant technical challenge for LWD fluid sampling jobs. Alternatively, this new method could be integrated with other pressure transient techniques to improve the interpretation of measurements. For example, in a pretest case where the pressure transient does not achieve the radial flow regime, fluid cleanup could provide complementary information about late-time flow regimes to enhance the acquisition of measurements in real time.
We document synthetic and field examples of applications of a new interpretation method. Seven reservoir cases are simulated to obtain contamination data: (1) homogeneous isotropic reservoir, (2) formation thickness, (3) laminated formations, (4) geological faults, (5) mud-filtrate invasion (6) reservoir properties, and (7) permeability anisotropy. All these cases are compared for single-phase and multiphase flow during LWD fluid sampling operations. Additionally, field case studies are analyzed to highlight the value of the reciprocal contamination derivative (RCD) in real-time operations. Reservoir limits and features such as saturating fluid and depth of invasion are identified in the flow regimes detected with derivative plots of the reciprocal of the contamination. Consequently, LWD cleanup and sampling efficiency could be optimized based on contamination transient analysis by identifying the flow regimes taking place in the reservoir during filtrate cleanup, hence improving the prediction of the time required to acquire non-contaminated fluid samples.
The new approach of the reciprocal contamination derivative is an alternative way to optimize fluid cleanup efficiency and to quantify the spatial complexity of the reservoir during real-time LWD operations. In addition, this new technique enables the evaluation of reservoir properties in less operational time than PTA without the need of pressure build-up stages, increasing fluid sampling efficiency in terms of quality and time.
Selecting the best tool for a specific type of reservoir condition is a crucial part of a fluid sampling job. Moreover, uncertainty in sample quality increases when the fluid phases are miscible. On a recent logging job, a formation tester was used to acquire water samples across a zone drilled with water-base mud (WBM). We examine the performance of several probe configurations (both existing and prototype) under equivalent reservoir conditions to quantify and optimize filtrate cleanup efficiency. The study is carried out using a compositional simulator for a water-saturated reservoir invaded with blue-dye tracer included in WBM filtrate.
History matching of field measurements allows the calibration of the model for further modification to account for a variety of reservoir conditions. Complex tracer dynamics of a blue-dye WBM invading a water-saturated formation and fluid pumpout are accurately and expediently modeled using a flexible numerical algorithm to account for different probe types and tool configurations. Under normal operating conditions, the chosen formation tester would have taken around one hour to clean the filtrate contamination to a target value of 5%. On the other hand, the best choice was the Focused Elliptical Probe, for which fluid cleanup would take less than 40 minutes. Additionally, a different tool configuration with a combination of multiple probe geometries spaced radially around the tool would provide faster cleanup times of only 32 minutes, thereby saving rig time.
We rank eight formation testing tools designs under equivalent reservoir conditions. The examples highlight the importance of probe geometry and configurations together with reliable and expedient numerical modeling during the pre-job phase to reduce cleanup time in anticipation of complex reservoir conditions. Furthermore, numerical simulations compare the fluid cleanup efficiency for various commercial formation-testing probes together with innovative probe designs that could potentially lead to a new tool or probe development. Perfecting both probe geometry and fluid pumping schedule is the most important output of our study.
Xu, Song (School of Geosciences, China University of Petroleum–East China, and Petroleum and Geosystems Engineering, University of Texas–Austin) | Tang, Xiao-Ming (China University of Petroleum–East China) | Torres-Verdín, Carlos (Petroleum and Geosystems Engineering, University of Texas–Austin) | Su, Yuan-Da (School of Geosciences, China University of Petroleum–East China)
Subsurface rocks often contain cracks/fractures with various orientations: aligned, conjugated, and randomly oriented, giving rise to different types of seismic anisotropy. We develop an effective elastic-wave scattering theory to accurately calculate anisotropy properties in the presence of single and/or multiple fracture sets. Two specific models, the equivalent aligned crack system (EACS) and the equivalent orthogonal crack system (EOCS), are considered for the calculations. The EACS generates significant anisotropy while the EOCS exhibits weak anisotropy due to the interaction of cracks with different orientations. The theory is applied to interpret acoustic anisotropy measurements acquired in hydraulically fractured formations. Theory and measurements are in good agreement.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 205A (Anaheim Convention Center)
Presentation Type: Oral
Interpretation of two-phase production logs (PLs) traditionally constructs borehole fluid-flow models decoupled from the physics of reservoir rocks. However, quantifying formation dynamic petrophysical properties from PLs requires simultaneous modeling of both borehole and formation fluid-flow phenomena. This paper develops a novel transient borehole/formation fluid-flow model that allows quantification of the effect of formation petrophysical properties on measurements acquired with production-logging tools (PLTs).
We invoke a 1D, isothermal, two-fluid formulation to simulate borehole fluid-phase velocity, pressure, volume fraction, and density in oil/water-flow systems. The developed borehole fluid-flow model implements oil-dominant and water-dominant bubbly flow regimes with the inversion point taking place approximately when the oil volume fraction is equal to 0.5. Droplet diameter is dynamically modified to simulate interfacial drag effects, and to effectively account for variations of slip velocity in the borehole. Subsequently, a new successive iterative method interfaces the borehole and formation fluid-flow models by introducing appropriate source terms into the borehole fluid-phase mass-conservation equations.
The novel iterative coupling method integrated with the developed borehole fluid-flow model allows dynamic modification of reservoir boundary conditions to accurately simulate transient behavior of borehole crossflow taking place across differentially depleted rock formations. In the case of rapid variations of near-borehole properties, frequent borehole/formation communication inevitably increases the computational time required for fluid-flow simulation. Despite this limitation, in a two-layer reservoir model penetrated by a vertical borehole, the coupling method accurately quantifies a 14% increase of volume-averaged oil-phase relative permeability of the low-pressure layer caused by through-the-borehole cross-communication of differentially depleted layers. Sensitivity analyses indicate that the alteration of near-borehole petrophysical properties primarily depends on formation average pressure, fluid-phase density contrast, and borehole-deviation angle. A practical application of the new coupled fluid-flow model is numerical simulation of borehole production measurements to estimate formation average pressure from two-phase selective-inflow-performance (SIP) analysis. This study suggests that incorporating static (shut-in) PL passes into the SIP analysis could result in misleading estimation of formation average pressure.
Sonic logs are widely used to estimate seismic wavelets via synthetic seismograms. Deleterious noise present in sonic logs can bias the estimation of seismic wavelets, hence degrade the quality of seismic inversion-based products. We introduce a new method to mitigate processing errors and borehole environmental noise that typically contaminate sonic logs. The method works for vertical or slightly dipping wells. We reduce noise present in sonic logs by first inverting the shear and compressional logs in the estimation of rock elastic properties and then using the estimated properties to recalculate the sonic logs. To increase the speed of forward modeling, and therefore the speed of inversion, we use axial sensitivity functions, which are equivalent to the Green's functions of borehole acoustic measurements. Axial sensitivity functions depend on tool, borehole, and formation properties. Our method is first tested on synthetic wireline sonic logs contaminated with noise. Resulting logs are noise free and the method accurately estimates layer-by-layer elastic properties of the synthetic formation. We then apply the noise-reduction method to sonic logs acquired in the deepwater Gulf of Mexico. Results verify the reliability and stability of the new inversion-based algorithm. While alternative methods invoke numerical filters to eliminate noise and spikes, our method is based on actual sonic tool and formation properties to mitigate noise. Using geometrical and physical constraints for noise reduction rather than filters yields sonic logs that more accurately reflect the physical properties of rock formations penetrated by wells.
Presentation Date: Monday, October 17, 2016
Start Time: 2:15:00 PM
Presentation Type: ORAL
Summary We developed an efficient parallel 3D inversion method to estimate electrical resistivity from deep directional borehole electromagnetic (EM) induction measurements. The method places no restrictions on the symmetry of the assumed subsurface model and spatial distribution of electrical conductivity, and supports arbitrary well trajectories. Parallel direct solvers are employed for fast forward modeling of triaxial induction problems with multiple transmitter-receiver positions. Optimal transmitter-receiver configurations for several induction frequencies are determined for different application conditions. Numerical inversion results of challenging synthetic data confirm the feasibility of full 3D inversionbased interpretations, thus opening the possibility of integrating directional induction measurements with seismic amplitude data for improved petrophysical and fluid interpretations.
Spherical- and cylindrical-based analytical models are frequently used to estimate reservoir flow properties from Formation-Testing (FT) measurements. Solutions to these equations are developed under restrictive assumptions which compromise their reliability over a wide range of field conditions. On the other hand, a Wellbore Numerical Simulator (WNS) enables improved understanding of complex flow systems (
To conduct the work, a multi-dimensional, single-well, finite-difference model is developed for forward modeling of FT operations. The formulation of the algorithm allows simulating either single- or two-phase flow. Additionally, the numerical code couples an analytical mudcake growth model to simulate the process of mud-filtrate invasion.
We perform radial numerical simulations to quantify the impact of multiphase flow on otherwise singlephase equivalent pressure transients. The study includes effects of pressure-dependent oil properties and two-phase relative permeability. Findings from synthetic cases indicate that such multiphase effects on pressure transients are negligible except in the presence of extreme pressure drops and substantial spatial variations in mobility; for a wide range of testing and reservoir conditions, the pressure signal is mostly governed by combined rock-fluid properties. For PTA purposes, the latter behavior justifies the implementation of a single-phase type model for fast and accurate flow-regime identification and estimation of total mobility.
The above results are confirmed with a field study where measurements were acquired in a multiphase environment. Common practices in numerical interpretation of FT measurements would suggest the need for multiphase algorithms. Nonetheless, excellent pressure history matching is attained with the developed WNS in single-phase mode. Such results confirm that, under suitable testing (and reservoir) conditions, FT pressure transients chiefly respond to spatial variations and total flow properties.
Our work confirms the feasibility of identifying testing conditions such that the recorded pressure is negligibly affected by individual-phase flow properties. The single-phase equivalent model developed in this paper, applicable under such conditions, provides fast and accurate quantification of flow zones without a-priori multiphase flow information.
Ramos, Matthew J. (The University of Texas at Austin) | Espinoza, D. Nicolas (The University of Texas at Austin) | Torres-Verdín, Carlos (The University of Texas at Austin) | Shovkun, Igor (The University of Texas at Austin) | Grover, Tarun (Statoil)
Simultaneous ultrasonic wave propagation and triaxial-stress testing are used to investigate the effects of fractures on the dynamic and static mechanical properties of clastic rocks under varying stress loading paths. The first case study explores the influence of pre-existing artificial fractures, while the second investigates the effects of deviatoric stress-induced microfracture development. Experimental results indicate that presence of fractures distinctly decreases wave velocities, with calculated dynamic elastic moduli decreasing by up to 7.5% in artificially fractured sandstone. Fracturing also tends to amplify the stress dependence of wave attenuation and the filtering of high-frequency wave components. Results also show a divergence of shear wave velocities polarized at 90° due to the development of microfracturing well before shear failure under deviatoric loading. This behavior occurs simultaneously with decreases in shear wave velocity and increasing stiffness nonlinearity, and is consistently aligned with the onset of rock dilatancy. Our study highlights the potential for full waveform analysis in sonic wellbore logging for in-situ fracture diagnostics, and the utilization of shear wave anisotropy to characterize rock damage.
Oil and gas production from unconventional reservoirs provides new avenues for energy production in the US, accounting for 78.2 Bbls of crude oil, and 949.3 Tcf of natural gas. This equates to roughly 30% and 41% of the technically recoverable oil and gas in the US respectively . Although unconventional formations have become increasingly important for the oil and gas industry, the need for horizontal drilling and hydraulic fracturing force narrow profit margins, and low oil prices further decrease their financial feasibility.
Core samples from unconventional plays exhibit minimal matrix permeability, however mudrocks are often laden with natural fractures on many scales . Natural fractures not only act as planes of weakness for rock failure, facilitating the branching of hydraulic fractures, but they are also preferential conduits for the flow of hydrocarbons to the wellbore . Because evidence links natural fractures in tight reservoirs to increased production during hydraulic fracturing, gaining insight into the density and spatial distribution of natural fractures prior to hydraulic fracturing is vital for optimizing hydraulic stimulation efforts and maximizing hydrocarbon recovery .
Several methods have been developed for detecting, imaging, and characterizing natural fracture patterns and their relative abundance. Specifically, analysis of rock outcrops, core samples, well imaging and testing (DFIT/LOT), and microseismic data are among the most common, and most useful techniques for estimating the spatial distribution and density of natural fractures in the subsurface [5, 6]. Although each technique provides valuable information, their inherent limitations leave large technological gaps in our ability to utilize natural fractures to guide enhanced stimulation. Tool resolution, sample scale, depth of investigation, and sample disturbance are some limitations to in-situ characterization of natural fractures on micro scales and beyond the wellbore [7, 8, 9].
Conventional practices in the interpretation of formation-tester (FT) measurements invoke spherical- and/or cylindrical-based analytical models. Solutions to these equations are primarily limited to spherical or point sources, homogeneous reservoirs, and/or spherical/hemispherical flow regimes. Such assumptions compromise the reliability of the analytical models over a wide range of practical field conditions. To address this challenge, a wellbore numerical simulator (WNS), although more complex, is adapted in this study to enable precise probe shape modeling, and reliable identification and quantification of spatially variable flow systems.
Understanding the effect that different probe shapes have on FT pressure transients permits identifying tool geometries that maximize early-time rock-fluid effects on the pressure signal. Moreover, quantifying the extent to which anisotropy, relative dip, tool position, heterogeneity and supercharging further influence the pressure transient necessities modification of probe-shape correction coefficients, where a WNS eliminates these corrections for improved FT pressure transient analysis (PTA).
A detailed three-dimensional (3D) finite-difference single-phase flow WNS for FT operations was developed that includes circular and elongated probe geometries and dual packers. The algorithm honors a full permeability tensor formulation, and supports mud-filtrate invasion and mudcake growth. A numerical simulation study is performed to quantify the dependence of pressure transients on probe shapes. Findings emphasize the flow-apparent distortion of the spatial coordinates due to the elongated profile of oval probes. This phenomenon indicates that for the same velocity, and for a wide range of typical anisotropy ratios, elongated probes cause less pressure drop than circular ones.
Furthermore, a thorough study of analytical and numerical simulation results is performed to assess the impact of factors influencing FT pressure transients, while appraising the need for probe shape correction coefficients. Results indicate that available point-source cylindrical-based analytical solutions properly predict middle to late time flow regimes, except for supercharged and heterogeneous dipping systems. Moreover, due to the lack of actual tool geometry, current point-source models provide flawed estimates of flow properties. This work also indicates that WNSs permit reliable job planning, better understanding of complex flow systems, improved FT-PTA, and estimation of not only spherical mobility but, more importantly, anisotropy.