The measurement of geomechanical properties of reservoir rock and caprock for completion optimization, enhanced oil recovery (EOR), and disposal/storage of any kind is becoming an integral and key aspect of asset evaluation and appraisal. One of the most important of these characteristics is an in-situ evaluation of the magnitude and variation of the minimum in-situ stress, the measurement of which is critical for geomechanical modelling and thereby a range of applications such as well construction, caprock integrity, and completion optimization. A wireline formation testing (WFT) tool is a common approach for obtaining direct measurements of these stresses at a range of depths. This process is referred to as microfracturing and is most typically performed in an openhole environment. Typical toolstrings consist of a straddle packer arrangement, a pumping mechanism, gamma ray for accurate depth correlation, a motorized valve/manifold arrangement, and pressure/temperature gauges. To perform a stress test, a specific interval of the wellbore is isolated by inflating the straddle packers. The interval is then pressurized by incrementally pumping fluid until a tensile fracture has been initiated. In an open hole, the fracture will initiate and propagate normal to the minimum stress at the wellbore and multiple injection and falloff cycles are subsequently performed to ensure fracture growth beyond the influence of the hoop stress regime. The data are then analysed to determine fracture initiation, reopening, propagation and closure pressures. Additionally, it may be possible to approximate fracture orientation, if an image log is available. This paper describes the process of obtaining minimum in-situ stress measurements using a WFT and advanced integrated stress analysis (ISA) process, in an ultradeep reservoir at ultrahigh pressures. Lessons learned and best practices are highlighted along with their importance for efficient job execution. The integrated geomechanical analysis covers subsequent generation of a calibrated stress model with minimum horizontal stress measured during microfracturing. Factors include evaluation of the stress contrast in the target formations and evaluation of the overburden gradient and mechanics for microfracturing job design for future operations (breakdown pressure) and lessons learned such as station selection, backup packer availability, and influence of stress cage material on breakdown, to name but a few. Obtaining accurate knowledge of in-situ minimum stress values, based on actual measurements, is a key step on the road to effective execution, and the earlier that this is achieved, the more efficient the results of any development. This paper summarises the successful application of the WFT approach in delivering such data under extremely harsh depth and pressure conditions, but resulting in a measurement from which numerous subdisciplines can conduct their decision making and design.

The recent growth in horizontal well technology has resulted in existing oil and gas vertical development plays to be evaluated for horizontal well applicability. As operators attmept to evaluate the criteria for converting from vertical well plays to horizontal well plays, sound data gathering and modeling become crucial to understand how completion strategies needs to be modified for improved production, without utilizing an expensive trial and error methodology. The Powder River basin contains a variety of producing shales and sands currently being explored for vialibility (i.e. Niobrara, Frontier, etc). In this study, reservoir and fracture properties are estimated based on hydraulic fracture modeling, rate-transient analysis techniques and production history matching to calibrate log data measurements. The challenges associated with calibration and modeling measurements from petrophysical and rock mechanics models are compared with hydraulic fracture and production modeling results to understand the direction of optimization and future basin growth. Past experiences are typically the basis for design and implementation of developing a new drilling and completion program. Interpretation of the hydraulic fracture behavior is often inferred from simple diagnostics, and as production ensues the repeatability for success or failure is often attributed to modifying the hydraulic fracturing program or geological influences, which is subject to inconsistency and qualitative introspection. Within this study a single well modeling approach is utilized to understand fracture geometry, correlate this with production history matching results, and distinguish production attribution from hydraulic fracture characteristics or reservoir properties. Exercising this workflow addresses challenges affiliated with modeling fracture propagation and production matching and the gap associated with horizontal well development in existing vertical plays.

Over the years, triaxial induction tools have found applications in not only determining formation resistivity, anisotropy, and dip, but also in detecting fractures. Fracture detection techniques provide useful information in identifying fractured reservoirs because fractures provide both space for hydrocarbon storage and also the channel for fluid flow. When fractures are developed in a formation, the formation can exhibit triaxially anisotropic conductivity if the fractures are filled with a fluid with a significantly different conductivity than that of the formation. This is particularly true for transversely isotropic formations. In an isotropic sedimentary formation, fractures can also cause the formation to be triaxially anisotropic if the geometric properties, orientation and porosity of fractures are varied from place to place in the fractured zone. In this paper, we present a new method that uses the information of the conductivity tensor to detect fractures. The new method indicates the presence of contrasting fluid-filled fractures by the difference in three conductivity components of the tensor. This difference is called triaxiality in the paper. The conductivity tensor is found using an inversion approach. In addition to three conductivity components σx, σy, and σz, the inversion also provides three Euler angles γ, α, and β. Multiple initials for Euler angles are used to ensure that a global minimum is obtained. The inversion is followed by a rotation operation on the inverted conductivity tensor to eliminate the ambiguity effect of the principal coordinate system. The new Euler angles are found by solving a minimization problem. We have applied the new method to both synthetic and field examples. Synthetic examples show that the rotation operation is indispensable to remove the ambiguity effect of the principal coordinate system. Furthermore, it is shown that the triaxiality is indeed responsive to the presence of fracture. Previous processing of the field example has showed that fractures exist in many zones. The triaxiality index derived from the new method is found in a fairly good agreement with the fracture index from a previous method.

Salt drilling in Deepwater Gulf of Mexico (GOM) presents unique challenges. One of these challenges is the effect salt has on ranging technologies used in contingency relief well designs. A new technique called Active Acoustic Ranging (AAR) addresses the challenge of locating and tracking the target wellbore to the interception phase. This case study details the degree of precision that this new technique provided while locating two nearby wellbores within salt. This study is intended to improve industry awareness and understanding of relief well ranging options available to the industry, specifically wellbore ranging activities conducted within a salt formation. Sonic logging started in the early 1930s to determine rock characteristics by measuring the refracted signals from a combination of transmitters and receivers. The technique evolved by recording acoustic signals beyond the refracted zone, by positioning the transmitters and receivers downhole in the logging tool. AAR utilizes surface seismic processing methods to determine azimuthal direction and distance of compressional and shear acoustic signals, reflected from around the borehole. After processing the reflected signals, the distance and direction of nearby wellbores can be determined. This can be effective in salt formations, where resistivity inhibits use of active electromagnetic ranging tools. This case study presents test results conducted in a GOM Deepwater operation to locate two nearby wellbores, a cased hole and an open hole, using AAR. It shows that AAR signals can be successful in locating offset wellbores within salt formations. The acoustic signals, both compressional and shear, were recorded using a stack of 13 receivers. Each stack had 8 sector azimuthal receivers to determine the distance and direction of the corresponding target wellbores. By utilizing compressional and shear signals generated from the various distances of monopole and dipole transmitters, a redundant process was provided to determine the location of the target wellbores with a high degree of accuracy. In addition, the acoustic images provided estimates of the salt quality, which can be used to select the interception location for hydraulic kills. The maximum ranging distance is dependent on the velocity and attenuation of the transmitted acoustic signals in the traversed formations. Salt typically has higher velocities that will enable ranging at greater distances than other formations. One of the primary benefits of this technique is the ability to provide two different measurements using monopole and dipole sources to locate nearby wellbores. This reduces uncertainties that may arise when ranging with a system using only a single measurement. AAR benefits from the salt formation, whereas other ranging technologies, i.e. electromagnetic, were not optimized for salt. AAR increases the ranging options in salt formations.

Accelerating the learning curve in a fluvial tight-gas development program can be achieved by understanding the impact of reservoir quality and completion properties on well productivity. Too often completion changes are made over a small sample (statistical) wherein numerous parameters (proppant volumes/type, gel-loading, etc) are changed without clear accountability of the variation in local geology and reservoir quality. This complicates basic production analysis techniques and can be a costly practice to determine the direction in which optimization should proceed.Various proppants, fluid types and design schedules were analyzed to quantify the impact of these designs on productive fracture half-lengths and conductivity. Calibrated fracture propagation models were also utilized to relate these productive properties (fracture length, conductivity and permeability) to stress profile, gel-loading and proppant types via fracture propagation models. The development of calibrated mechanical properties, petrophysical models and understanding of current hydraulic fracture and reservoir properties thus enabled redesigning of future completions and the analysis of these completions. This paper demonstrates the application of appropriate fracture propagation models, rate-transient analysis and production history matching techniques to understand the direction in which completion design changes must move to increase productivity.