A system of exceptionally well-exposed, early-burial fractures in outcrops of Devonian carbonates on the Lennard Shelf, Canning Basin, Western Australia, serves as an analogue for fractures in deep reefal carbonate petroleum reservoirs in the Precaspian Basin of Kazakhstan. Data from early fractures were collected at Windjana Gorge, which crosscuts such a reefal depositional system. Less extensive evaluations were also made at three auxiliary sites along the Lennard Shelf. These early-formed, near-vertical fractures strike parallel or normal to the strike of the Devonian depositional margin. Fracture density correlates with the textural character of the host rock, with the highest values in boundstone-rich rock, lowest values in grain-rich rocks, and intermediate values in rocks of mixed assemblage, including breccia. Fracture density is also controlled in part by the mechanical character of bedding at the time the fracture system developed, syndepositionally or soon after. The environment of deposition (EoD) shows a weaker correlation with fracture density. At Windjana Gorge, fracture height correlates with the EoD, with the largest values in the reef core, progressing serially to shorter average height in the upper slope, middle slope, reef flat, and platform top/reef flat (a transitional EoD). To better understand the fracture size distribution within a reservoir that can influence fluid drainage, we introduce a new parameter, the intersected fracture height density (IFHD). This describes the aggregate fracture height connected directly to a traverse line or borehole. Because IFHD requires the measurement of fracture heights, it is measurable only at outcrop analogue exposures.

Production and well intervention history for the Rokan Light Oil, Sumatra, Indonesia operations region spans 90 years across 115 fields and more than 5000 wells. This vast production history results in large and diverse datasets that are difficult to manage. A simple and cost-effective data analytics solution, the "Well History Browser", was developed using the Data Analytic Application platform to address issues of big data management and analysis. Prior to development of the Well History Browser, Petroleum Engineer and Earth Scientist workflows relied on the need to work through multiple software platforms, such as web access portals, well log applications, homeless local drive files, and purpose-built Excel spreadsheets. Complicating matters was the fact that most legacy tools were developed for specific field assets and were not transferable to other assets within the organization. Furthermore, many of the tools were dependent on specific developers for maintenance and modification, which made it difficult to keep the tools working after staffing and organizational changes. The Well History Browser was developed to address these issues by providing a compact and efficient access point to all information within a single platform analysis. Data streams available within the analysis include a complete history of well metadata and status, allocated production and injection, well tests, well interventions, well opportunities, swab tests, spinner surveys, pressure surveys, perforations, and wellbore equipment. Example workflows that use the Well History Browser include offset / analog well production analysis for infill drilling, workover opportunity assessment and planning, daily field and well performance monitoring, subsurface integrity monitoring, decline type curve analysis, and production forecasting. Key enablers for development of the tool include construction of custom database tables and views, the use of data-on-demand database connections, IronPython scripts (streamlines the analysis by enabling development of shortcuts and automation), and TERR scripts (extends the computational power to allow for development of custom analyses). Shortly following release two years ago, the user-friendly tool was rapidly adopted by petrotech staff across the organization. The current daily user base is greater than 70 staff. Since initial release, tool developers have responded to user feedback by implementing visualization changes, adding analytic functions and creating automated workflows, all of which have been facilitated by the richly featured, low-code development platform. The Well History Browser has had a profound impact on staff efficiency in reducing cycle time spent in accessing well data and in increasing effectiveness in production data analysis. The result has been an increase in the quantity and the quality of well intervention and infill well opportunity identification.

SummaryA systematic work-flow to integrate pressure-transient data collected from single-well buildup tests in numerical reservoir-simulation models for a fracture/matrix system is presented. The results of its application in a sector model in the southeast region of Tengiz field in Kazakhstan are also discussed.The procedure starts with a selected numerical-simulation model, either a discrete fracture/matrix (DFM) model or a dual-porosity dual-permeability (DPDK) model, and follows with the analysis of a numerically generated buildup test to calculate the fracture spacing and shape factor of the model. Then, following the correlations between pressure-transient-analysis results and the average or representative values of the model-input parameters near the well, which contain the previously obtained fracture spacing and shape factor, the numerical-model parameters are adjusted in each iteration to match the pressure-transient behavior observed in the buildup test including the interporosity flow between matrix and fracture and the radial flow in the total system.Before field application, the numerical-simulation results from both DFM and DPDK models were validated against analytical pressure-transient solutions for a dual-porosity system. The gridding and time-steps were calibrated to reproduce the analytical transient behavior. Finally, the new work-flow was applied to a sector model of Tengiz field in the southeast region focusing on two wells. Following the developed work-flow, a DFM model was constructed, and its fracture and matrix properties were adjusted to honor buildup-test data at both wells and the transient data collected during a pulse test conducted between them. The study results show that the key factors of a DFM model on buildup transient response are the fracture permeability, fracture aperture, and matrix permeability in the well-drainage area, and the dominant parameters on pulse-test response are the fracture permeability and matrix porosity in the influence area between the two wells. Using the correlations quantitatively for each simulation step could reduce the total number of iterations needed to converge to the numerical solution. The modified model also generated flow distribution along the wellbore, consistent with production-logging data at one well. The resulting sector map of pressure change during buildup test indicates the area with well-connected fracture network. Dynamic transient data contain rich information about reservoirs, and the effective integration of dynamic and static data would have a big impact on reservoir management by potentially minimizing the number of wells to be drilled, maximizing the production, and optimizing recovery.The novelty of this study is the quantitative use of the correlations between pressure-transient-analysis results and the representative values of the input parameters in a numerical model to reduce the number of simulation iterations. Its application in Tengiz is also one of the rare examples in which single-well and multiple-well transient data, production logging, and image-log data are all available.

Natural fractures bear significant influence on productivity in Tengiz field, which is one of several giant light-oil accumulations trapped in isolated carbonate platforms in the Pricaspian Basin of Kazakhstan. Outcrop analogs are particularly important for understanding reservoir fracture systems because many aspects of fracture character (e.g. height, length) are impossible to measure with subsurface data. The Devonian margin of the Canning Basin in NW Australia presents a well-exposed outcrop analog for steep margin and slope deposits of Tengiz field. Fracture data gathered from Tengiz core and image logs suggest affinity to fractures in the Canning outcrops in terms of origin, orientation, and range of density. Inclusion of additional information - gained through outcrop study - into reservoir fracture description leads to improved understanding of stratigraphic influence on their occurrence and character. Shallow-burial fractures – those formed in carbonate strata prior to significant burial, including neptunian fractures – are the most important for reservoir productivity at Tengiz field. These fractures dip steeply and strike dominantly parallel and/or normal to the local orientation of the depositional margin. They are most well-developed in brittle, boundstone-dominant facies of the outer-platform to upper slope environment. Dissolution by corrosive fluids following burial led to enlargement of fracture apertures, which range from small to cavernous. In Tengiz field, cavernous fractures pose both high lost-circulation risk, as well as the reward of highly productive wells. Outcrop data from the Canning Basin show fractures in the mid- to upper-slope facies and reef core are, on average, not limited by bedding and hence much taller than fractures in the reef flat and outer platform areas. Fracture size cumulative distributions are mainly exponential, and they differ between stratigraphic settings. We expect such size differences will have important effects on fracture connectivity and permeability in a reservoir. Fracture density, which is measured routinely in the Tengiz reservoir, was measured with long pseudowells (i.e. scanlines) “drilled” along Canning outcrops. Fracture density shows significantly less variation among facies than does fracture height. Thus, outcrop-based data can add substantially to our understanding of key fracture system characteristics that are unavailable from well data alone.

A 3-D mechanical earth model (MEM) was developed for Tengiz to predict the long-term response of a reservoir to field development. The study aims at understanding the impact of reservoir pressure depletion on reservoir compaction and surface subsidence. Tengiz Field, a deep, super-giant oil field located in western Kazakhstan near the north-eastern coast of the Caspian Sea, consists of Devonian through Carboniferous isolated platform carbonates with an aerial extent of approximately 440 sq. km (Figure 1). The top of the reservoir occurs at -3850 m TVDSS and the oil column is at least 1600 meters. Although the producing formation is deep and the reservoir rocks are competent, minor amounts of reservoir compaction and surface subsidence are nonetheless observed at Tengiz.

Abstract Brown-field Experimental Design (ED) was successfully applied to a super-giant oilfield to generate probabilistic (P10, P50, and P90) models to define the range of field performance and to mitigate the non-uniqueness in reservoir simulation. A recent trend in reservoir simulation has been to apply probabilistic modeling, such as, brown-field ED to develop multiple (P10, P50, and P90) models. Unfortunately, these probabilistic models are also non-unique because multiple input combinations can be used to generate the probabilistic responses observed during ED. The non-uniqueness of the probabilistic models may impact their usefulness in certain circumstances. For example, if these models are used to develop short-term signposts for long-term reservoir behavior, then the models may be influenced by the selection of reservoir data (e.g., a P10 model with one combination of input may have a different short-term "signature" than an alternate P10 model despite giving comparable P10 recovery). Also, the degree of success of a downside-mitigation (or upside-capture) strategy, and its ranking with other such strategies may be influenced by the input chosen to develop the models. For the super-giant Tengiz oilfield, brown-field ED was applied to a conventional history match with the primary objective of creating probabilistic models. Additionally, we developed tools to design multiple deterministic models with specific physical interpretations. With these deterministic models we can identify the signatures for specific reservoir phenomenon, such as, minimum/maximum OOIP, minimum/maximum compartmentalization, minimum/maximum reservoir energy, etc. All models built with these tools yield acceptable visual and quantitative history matches. In this paper we discuss how brown-field ED was used to post-process a conventional history match. We present a case study for the use of brown-field ED methods and illustrate the proposed approach to mitigate the non-unique nature of reservoir simulation. While the impact non-uniqueness can be mitigated, we also recognized that it can never be completely eliminated.

Mechanics-based restoration has been seen by some in the structural geology community as a panacea – a new technology that melds the retrodeformational merits of kinematic balancing with principles of continuum mechanics. The method has been touted for its ability to simulate complex 3D systems without assumptions of plane strain, allowing for heterogeneous fault slip distributions and mechanical interaction of fault segments. It has been suggested as a means to predict distributions of geologic strain and associated small-scale structures; however, we demonstrate that the kinematics of restoration models may differ significantly from forward deformation. Restoration models are governed by boundary conditions that are different from the forces driving forward geologic deformation. Models may be improved by supplementing restoration boundary conditions with loads that attempt to reverse tectonic strain, but unphysical artifacts persist. Mechanics-based restoration may be an appropriate tool for traditional applications of kinematic models including validation of structural interpretation and modeling geometric evolution; however, more subtle features, particularly strain distribution, should be treated with skepticism. Restoration models may provide insights to the initial configuration of forward mechanical models with physically appropriate boundary conditions and non-linear material behavior. Forward models provide the best means for simulating deformation and predicting subsidiary structures.

Differential compaction associated with prograding and aggrading steep-sloped carbonate margins leads to penecontemporaneous and post-depositional modifications of stratal geometries and tensile and shear stress concentrations that might result in brittle deformation. In an effort to investigate controls on these deformation processes, we employ a step-wise gravity loaded elastic model that captures pre-failure displacement and stress field patterns for a depositional geometry based on the Permian Capitan depositional system, Guadalupe Mountains, West Texas and New Mexico, USA. We consider four model geometries with varying progradation to aggradation (P/A) ratios, from strongly prograding (P/A=10) to strongly aggrading (P/A=0.1). The strongly prograding case (P/A=10) is used for sensitivity analysis that investigates the effects of varying rock mechanical properties of basin and platform facies. Model results yield relatively consistent patterns of deformation and stress that include: (1) a region of enhanced subsidence centered near the platform margin, (2) basinward displacement of the platform margin that decreases down slope, and (3) positive maximum Coulomb stress and positive (tensile) stress, both in-plane and out-of-plane, near the platform margin and in adjacent slope and platform facies. The patterns of deformation for the strongly progradational model are strikingly similar to present day stratal geometries of the Capitan depositional system that are often inferred to be primarily depositional in origin. Model results suggest that these geometries are established immediately upon deposition and may therefore affect the stratal architecture of the margin, but significant additional deformation also occurs during subsequent platform growth. We interpret the regions of positive Coulomb stress and tensile stress as areas likely to fail by faulting or jointing, respectively. This inference is corroborated by field observations of early-formed brittle deformation features in the Capitan margin. Our geomechanical models of the Capitan margin suggest that early-formed deformation is an integral part of the general steep-sloped carbonate system.

To refine flow models for sand-dominated fault rock, we present petrophysical data of host and fault rock samples from the eolian Aztec Sandstone, Valley of Fire State Park, Nevada, that has been deformed by strike-slip faults formed by progressive shearing along joint zones. The data include bulk mineralogy, porosity, permeability, grain-size distribution, and mercury-injection capillary pressure measurements of 40 host, fragmented, and fault rock samples. To investigate the impact of shear strain on fault zone properties, three sample localities with average shear strains of 28, 63, and 80 were investigated (25–160-m [82–525-ft] slip). No bulk mineralogical changes caused by fault zone cementation or mineral alteration were detected when comparing host and fault rock. Fault rock permeability is one to three orders of magnitude lower than median host rock permeability. Porosity reductions are less pronounced and show considerable overlap in values between the sample suites. Some fault rock samples appear to have dilated with respect to median host rock porosity. Median grain sizes for fault rock samples range from 3 to 51 m, which is as much as two orders of magnitude reduction from host rock median grain sizes. There appears to be a lower limit of median grain size of 3 m for fault rock samples irrespective of average fault shear strain. Fault rock capillary injection pressures range from one to almost two orders of magnitude higher than the host rock equivalent. For standard fluid properties, calculated maximum sealable hydrocarbon column heights range between 10 and 70 m (33 and 230 ft) of gas and 20–120 m (66–400 ft) of oil. These petrophysical data show that faults formed by shearing of joints in high-permeability, sand-prone systems will act as significant barriers to fluid flow during reservoir production and might be capable of sealing small to moderate hydrocarbon columns on an exploration timescale as well, assuming adequate continuity of the fault rock over large areas of the fault.

Models for the evolution of faults formed by shearing along joint zones in Aztec sandstone, Valley of Fire, Nevada predict damage zones either localized within the fault core or symmetrically distributed about the core or a slip surface therein. We expand these models by presenting two examples of faults with asymmetric damage zones from the same field locality. Asymmetric damage is attributed to the inherited geometry of a parent joint with a peripheral joint breakdown fringe. One example is of a fault formed along a parent joint with continuous breakdown fringe. The other example is of a fault formed in part along a parent joint with abrupt breakdown fringe. When compared with the symmetric examples, the damage in the asymmetric cases is minimized due to the presence of an already through-going surface.