Search Results (5)

The petroleum reservoir represents a complex heterogeneous system that requires thorough characterization prior to the implementation of any incremental recovery technique. One of the most commonly utilized and successful secondary recovery techniques is waterflooding. However, a lack of sufficient investigation into the inherent behavior and characteristics of the reservoir formation in situ can result in failure or suboptimal performance of waterflood operations. Therefore, a comprehensive understanding of the geological history, static and dynamic reservoir characteristics, and petrophysical data is essential for analyzing the mechanisms and causes of waterflood inefficiency and failure. In this study, waterflood inefficiency was observed in the Morrow B reservoir located in the Farnsworth Unit, situated in the northwestern shelf of the Anadarko Basin, Texas. To assess the potential mechanisms behind the inefficiency of waterflooding in the east half, geological, petrophysical, and reservoir engineering data, along with historical information, were integrated, reviewed, and analyzed. The integration and analysis of these datasets revealed that several factors contributed to the waterflood inefficiency. Firstly, the presence of abundant dispersed authigenic clays within the reservoir, worsened by low reservoir quality and high heterogeneity, led to unfavorable conditions for waterflood operations. The use of freshwater for flooding exacerbated the adverse effects of sensitive and migratory clays, further hampering the effectiveness of the waterflood. In addition to these factors, several reservoir engineering issues played a significant role in the inefficiency of waterflooding. These issues included inadequate perforation strategies due to the absence of detailed hydraulic flow units (HFUs) and rock typing, random placement of injectors, and uncontrolled injected fresh water. These external controlling parameters further contributed to the overall inefficiencies observed during waterflood operations in the east half of the reservoir. A detailed understanding of the mechanistic factors of inefficient waterflood operation will provide adequate insights into the development of the improved recovery technique for the field. Full article

Correct estimation of hydraulic fracture height growth is a critical step in the design of Hydraulic Fracturing (HF) treatment, as it maximizes the reservoir stimulation and returns on investment. The height of the fractures is governed by several in situ conditions, especially stress variation with depth. The common workflow to estimate stress is by building the mechanical earth model (MEM) and calibrating it using the Diagnostic Fracture Injection Test (DFIT). However, DFIT interpretation is a complex task, and depending on the method used, different results may be obtained that will consequently affect the predicted hydraulic fracture height. This work used the tangent and compliance methods for DFIT interpretation, along with isotropic and anisotropic stress profiles, to estimate the HF height growth using numerical modeling in a 3D planar HF simulator. Data from two wells in the Anadarko Basin were used in this study. The predicted height was compared with microseismic data. The results showed that even though the tangent method fits better to the isotropic stress profile, HF did not match with the microseismic data. On the contrary, the anisotropic stress profile showed a good match between the compliance DFIT model and the microseismic events. Based on the discussions presented in this study, the validity of the DFIT interpretation is debatable, and when the formations are anisotropic, the isotropic model fails to correctly estimate the minimum stress profile, which is the main input for the estimation of the fracture height. This is in addition to the fact that some researchers have questioned the use of the tangent method in low-permeability formations. Full article

This study reports on analyses of natural, geologic CO₂ migration paths in Farnsworth Oil Field, northern Texas, where CO₂ was injected into the Pennsylvanian Morrow B reservoir as part of enhanced oil recovery and carbon sequestration efforts. We interpret 2D and 3D seismic reflection datasets of the study site, which is located on the western flank of the Anadarko basin, and compare our seismic interpretations with results from a tracer study. Petroleum system models are developed to understand the petroleum system and petroleum- and CO₂-migration pathways. We find no evidence of seismically resolvable faults in Farnsworth Field, but interpret a karst structure, erosional structures, and incised valleys. These interpretations are compared with results of a Morrow B well-to-well tracer study that suggests that inter-well flow is up-dip or lateral. Southeastward fluid flow is inhibited by dip direction, thinning, and draping of the Morrow B reservoir over a deeper, eroded formation. Petroleum system models predict a deep basin-ward increase in temperature and maturation of the source rocks. In the northwestern Anadarko Basin, petroleum migration was generally up-dip with local exceptions; the Morrow B sandstone was likely charged by formations both below and overlying the reservoir rock. Based on this analysis, we conclude that CO₂ escape in Farnsworth Field via geologic pathways such as tectonic faults is unlikely. Abandoned or aged wellbores remain a risk for CO₂ escape from the reservoir formation and deserve further monitoring and research. Full article

The production of crude oil from resource plays has increased enormously over the past decade. In the USA, around 63% of total output in 2019 was from unconventional production. The major unconventional plays in the USA (e.g., Permian Basin, Anadarko Basin, Eagle Ford, etc.) have become some of the world’s largest oil producers. However, unlike “conventional” exploitation, the target zones in unconventional systems are generally the source rocks themselves or adjacent strata and require numerous horizontal wells and stimulation via hydraulic fracturing to meet production targets. In order to maximize production, operators have developed various well stacking methods, all of which require some form of monitoring to ensure that well spacing is optimized and fluid production is not being “stolen” from adjacent formations, thereby reducing the production potential in associated wells. This necessity, amongst other geochemical considerations related to source rock characterization, has resulted in the expansion of “production allocation” and “time lapse geochemistry” methods. These methods were initially developed for conventional production decades ago, but have since been adapted to unconventional systems. However, the direct applicability of this method is not straightforward and numerous considerations need to be taken into account, foremost among which are: (1) “What defines your end-members?” (2) “Are these end-members valid across a meaningful development area?” and (3) “What is the most appropriate use of geochemistry data in these systems?”. Reservoir geochemistry studies, which include both “time lapse geochemistry/production monitoring” and “production allocation”, are valuable geochemical methods in unconventional plays but need to be used appropriately to provide the cost savings and business direction that operators expect. In this paper, we will discuss a number of case studies, both theoretical and natural, and outline the important factors which need to be considered when designing a reservoir geochemistry study and the common pitfalls which exist. The case studies and best practice approach discussed are designed to highlight the power and flexibility of geochemical data collection methods, integration with the operator’s knowledgebase, and other analytical methods to customize the program for individual development programs. Emphasis is placed upon developing robust and applicable fluid relationships from geochemical data and evidence for statistically significant changes through time. Full article

Barite (BaSO₄) is a stable and widely distributed mineral in Earth’s crust. As such, barite has the potential to preserve specific geochemical and morphological characteristics representative of conditions at the time of its formation, which could be useful for interpretations of Earth’s ancient rocks and paleoenvironments. In this study, we used variations in saturation index, solution temperature, solution chemistry, presence of organics, and Mg²⁺ and Ca²⁺ ions to investigate variations in barite crystal morphology. Through 42 experiments, we simulated poorly understood, low temperature spring settings similar to Zodletone Spring in Anadarko Basin, Oklahoma. Using SEM/EDS, we identified barite rosettes, rounded barite, euhedral/square-shaped barite, and elliptical barite as the crystal morphologies that directly reflect different formational settings. The X-ray diffraction (XRD) patterns revealed different crystallographic characters of the four distinct barite crystal morphologies; in particular, the samples that precipitated from supersaturated SrSO₄ solution exhibited double peaks at 43° 2-Theta, which matched barite with strontium substitution as barite might have incorporated strontium in its structure. Barite crystals that formed in the presence of organics in the initial solution exhibited a double peak at 33° 2-Theta, which was absent in other samples. Confocal Raman microscopy indicated that all of the samples had typical barium sulfate bands, with a few differences in bands between the samples; for example, the 638 cm⁻¹ band showed splitting or a double band between different samples. The samples that precipitated from solution with organics had organic compounds from the experimental solution included in their composition. In both cases, C–H stretches from 2800 cm⁻¹ to 3000 cm⁻¹ were present as well as bands from 1350 cm⁻¹ to 1500 cm⁻¹, which are typical of organic compounds. Based on our experiments, the variation in barite crystal morphologies reflected changes in initial solution chemistry (or environmental settings). Full article