|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE-191437-18IHFT-MS, “ACA Practical Considerations: When Is It Accurate and How Should It Be Used To Improve Reservoir Stimulation,” by O.A. Ishteiwy, SPE, M. Jaboob, and G. Turk, BP; S. Dwi-Kurniadi, SPE, Schlumberger; A. Al-Shueili, SPE, A. Al-Manji, and P. Smith, BP, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed.
The use of diagnostic fracture injection tests (DFITs) for prefracture investigation has become routine in the oil field, particularly for understanding reservoir properties and subsequently optimizing hydraulic-fracture design. A key component of an effective DFIT is an after-closure analysis (ACA) to assess the transmissibility of the formation and allow for effective design. This paper describes a DFIT-analysis program and the suitability of the results from ACAs for use in hydraulic-fracture design.
The Khazzan field is being developed currently and includes multiple gas-bearing formations. The primary development reservoir is the Barik sandstone, which is characterized by permeabilities on the order of 0.1 to 1 md. An additional reservoir under development is the Amin formation, which lies deeper than the Barik and is perhaps more unconventional in nature, with estimated permeabilities an order of magnitude lower than the Barik formation. Both reservoirs require hydraulic fracturing to produce at economically attractive rates and, as such, carry the same sort of challenges to reservoir understanding inherent to all unconventional plays. This was recognized in advance of the appraisal program, and an approach was taken to address these challenges in a more-holistic fashion, encompassing a full suite of data gathering, including surveillance and well testing.
One of the key tools used was DFIT along with associated ACA of the decline to determine reservoir properties. During the appraisal phase, significant rigor was aimed at ensuring high-quality data would be recorded and that an appropriate amount of time would be allocated to monitoring pressure declines to enable valid interpretations. This resulted in the ability to draw a good correlation between data gathered from the ACA operations and data collected from post-fracturing well-test data.
Methods and Process Stimulation and Testing Sequence. The approach taken to stimulate and test the wells in Khazzan was to use a dedicated well-test unit. The overall sequence was as follows:
The Barik formation is a tight low-permeability conventional gas reservoir in the Sultanate of Oman comprising of a series of interbedded sandstones and shales. To achieve an efficient and economic development of this formation, the wells require the application of massive hydraulic fracturing operations, in order to achieve the required surface area and connectivity for production delivery.
Hydraulic fracturing operations often involve the use of a wide range of chemical components and the industry has understood for some time that chemical reactions take place both during and after fracture treatments have been performed. Post fracture treatment a wide range of differing chemical effects can take place and this may continue for some time during the extensive flowback and clean-up period. Such chemistries can result in a range of differing effects, including unplanned scaling tendencies, corrosional behaviour and can even influence aspects such as hydrate control. Such effects can also have an adverse impact on the well itself, the surface manifolding/valves, gathering system and production facilities and need to be well appreciated in order to remove issues.
During the early Appraisal of the Barik formation, in Block 61 in the Sultanate of Oman, H2S had been observed during the post-frac well-test operations. However, the Barik reservoir within the Khazzan field, was believed to be sweet and not reflect a measurable H2S; a characteristic that had been confirmed by performing pre-frac openhole sampling. As had been determined with fracturing operations elsewhere, it was surmised that the frac operations themselves where the potential source of the H2S. Potential causes for this included thermal decomposition of fluid chemistry as well as inadvertent contamination of original source water used for the feed fluid. It had been observed/measured, that the magnitude of H2S reduced with time and was directly related to fracturing fluid clean-up. After extensive investigation the evidence suggested that the root-cause was a combination of the presence of a hardy Sulphate Reducing Bacteria (SRB) species along with the presence of a thiosuplhate feedstock in the frac fluid.
This paper will present a full, robust and coherent analysis of the presence of H2S, the rigorous steps that were followed to identify the root-causes and the identification of potential sources/causes. The paper will present the preventive measures that have been taken and their impact on the overall temporary levels of H2S that have been seen in the operations since. The paper will go on to recommend that for future operations, particularly start-up areas, as transitory levels of H2S might not be identified, not because H2S is not there but rather that there is typically no apparatus nor sufficiently accurate surveillance in place on everyday operations to precisely identify such material.
The use of the Diagnostic Fracture Injection Test (DFIT) technique as a means of pre-frac investigation has become relatively routine in the oilfield, particularly to understand the reservoir properties and then subsequently optimize the hydraulic fracture design. A key component of an effective DFIT is the performance of an effective After Closure Analysis (ACA) to assess the transmissibility of the formation and thereby allow for effective design.
BP Oman is developing the Barik formation, within the Khazzan field, which is a low-permeability conventional tight-gas reservoir within Block 61 of the Sultanate of Oman. The reservoir is comprised of a series of tightly interbedded sandstones and shales, with substantial shale breaks between the principal sand lobes. During the Appraisal and Development well sequence to date, BP Oman have performed DFIT operations in over 50 vertical wells, within the Barik Formation. Each one of these wells was then subject to placement of a large (one million lb) hydraulic fracture treatment. Each treatment was then followed by a standard clean-up programme and when possible a PBU, with subsequent placement on production into the main gathering system.
This paper seeks to demonstrate that there is unambiguous evidence of a coherent correlation between the petro-physical Barik open-hole logs, the transmissibility value (as estimated from the ACA), the conventional Pressure Transient Analysis (PTA) as well as the long-term production behaviour. Additionally, the paper will investigate the key aspects of the actual DFIT execution, the data gathering and the analysis that can impact the quality of the correlation. The paper will go on to demonstrate the most efficient methods of achieving the most accurate assessment of the formation transmissibility; that is both indicative and subsequently helpful for the fracture design and post-fracture productivity prediction.
This paper successfully describes a 50 well, and growing, DFIT analysis programme and the suitability of the use of the results from the subsequently performed ACAs for forward planning and hydraulic fracture design. Providing a suite of useful and helpful insights, suggestions and recommendations; into how DFIT, for ACA, should be executed in the field; the paper adds an extensive case history to the industry database for future consideration.
Miqrat is a complex clastic deep tight gas reservoir in the North of the Sultanate of Oman. The Lower unit of the Miqrat formation is feldspatic sand characterized by low permeability not exceeding 0.1 mD and porosity up to 12 %. Based on results of the appraisal campaign of Field X, it contains significant volume of gas. However the production test data after fraccing showed mixed results. The objective of this study to explain the production behavior in relation to the frac geometry.
Understanding the reason of possible overestimation of log derived Hydrocarbon saturation is important. Thus the interpretation of conventional and special logs was revisited. In parallel, all the available core data including SCAL and thin sections were dissected. Besides, the analysis of hydraulic fracture propagation, well tests, cement quality, PLT including Spectral Noise Log was performed.
The wells were subdivided into categories according to their production. wells producing no water wells with water channeling from the water leg of Middle Miqrat wells with transition zone intervals with two-phase inflow of water and gas.
wells producing no water
wells with water channeling from the water leg of Middle Miqrat
wells with transition zone intervals with two-phase inflow of water and gas.
There are three main challenges that needed to be overcome. First challenge is to identify the high uncertainty in hydrocarbon saturation from the resistivity logs. Petrophysical evaluation shows that porosity profile derived from logs looks very similar in all wells with insignificant lateral variations. Hydrocarbon saturation estimated from logs looks also similar regardless of how deep or shallow the well is. However, production tests show different results, e.g. different flow rates and high water-cut are observed in some wells.
The second challenge to keep the frac height below the boundary between Lower Miqrat and Middle Miqrat, which consist of around 3 to 7 meters of shale and in most of the field it is bound with water. The third one is to cover the upper part of the zone below the shale since it is the best part of Lower Miqrat without breaking to the water leg of Middle Miqrat. A geomechanical model was created and several frac model iterations were run since in the early appraisal well that boundary was broken.
Investigation through multidisciplinary integrated team led to unlock the tight gas reserves in Lower Miqrat. Based on open hole log interpretation to create a geomechanical model. That model is being calibrated with DFIT, 3 different case hole logs and confirmed with production.
Efficient hydraulic fracturing is one of the most important aspects for wells in tight-gas reservoirs, in order to achieve and sustain economic production. Unlike North America, where thousands of wells are drilled and completed each year and with infrastructure in place, delivering a tight gas field development (Khazzan) in the Sultanate of Oman has very specific challenges related to the limited number of wells and poor existing logistical infrastructure. In order to address these challenges, improve the frac process and overall development efficiency, a suite of high-level goals were set for the initial development, including zero accident(s), 1 Bcf/day production, 300 wells and 40 mm.scf/day IP per well.
Within Block 61, in the Sultanate of Oman, the initial formation that was targeted for development was the Barik; a highly laminated gas bearing reservoir with measurable but tight permeability. The formation exhibits widespread heterogeneity in reservoir quality and rock properties in both the vertical and horizontal directions. Following an extensive exploration and appraisal programme, it was determined that vertical wells with massive hydraulic fracturing would be the most likely strategy for the higher permeability areas; with fractured horizontal wells being proposed within the lower permeability areas. This dual approach would provide the most efficient and effective development mechanism for the field and provide the greatest opportunity to deliver the simplistic development goals, as outlined above.
During the exploration, appraisal and development phases of Khazzan, incremental learning and step by step improvement was required as the phases changed both the emphasis and requirements. This began with measuring resources, ensuring adequate service provision and logistics, completion set-up and subsequent transition from appraisal to development mode. The identification of key fracturing aspects, such as in-situ stress-state and geo-mechanical understanding, as well as frac geometry determination (both placed and effective) were crucial to achieving development progress. Post frac flow-back, initial production behaviour and reconciliation with petro-physics all played their part in the delivery of a rapid transition to efficiency along with proof of resource.
This paper fully describes the technical and operational journey that was taken through the appraisal and early development phases, in order to fundamentally understand and deliver the most effective and efficient methods of hydraulic fracturing vertical wells in this tight-gas field. This case study includes the sequence of the first twelve vertical wells in the Barik reservoir; and the incremental improvements that were achieved in approaches over time. Fit for purpose technologies, equipment, procedures and surveillance have demonstrably led to a suite of very healthy and highly efficient completion approaches being adopted, which have ensured that the field development economics are being maximized.