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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 The paper has not been peer reviewed.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 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.
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 152436, "Application of Novel Technologies Helps Unlock Deep Omani Gas," by Andreas Briner, SPE, Joe Curtino, and Hisham Al-Siyabi, Petroleum Development Oman, and Tobias Judd, SPE, Schlumberger, prepared for the 2012 SPE Middle East Unconventional Gas Conference and Exhibition, Abu Dhabi, 23-25 January. The paper has not been peer reviewed.
With unique geomechanical, reservoir, and geological properties, some of the large gas-bearing prospects within the Fahud basin in the Sultanate of Oman require innovative drilling and completion practices. A revised drilling and completion workflow, with specific technology deployment and operational flexibility, has been developed in order to account for such reservoir complexity.
Early Paleozoic nonassociated-gas fields operated by Petroleum Development Oman in Oman have traditionally comprised good-reservoir-quality sand-stones located on three- or four-way dip-closed structural highs. While gas-exploration success has continued since 2005, discoveries have been restricted to much poorer reservoirs.
Successful continued exploration, appraisal, and further maturation, especially as exploration is also extended into basin-center locations, pose significant challenges given the depth (high temperature and high potential reservoir pressures) and reservoir quality [porosities ranging from less than 3% to 10%, with (ambient) permeabilities ranging from 0.001 to 1 md].
Following a successful completion of a regional basin-evolution and burial history study, a well campaign mainly targeting the Amin-Nimr section in the Fahud Salt basin was designed. The target reservoirs of the Amin formation and Nimr group are Cambro-Ordovician in age and are separated by the Angudan unconformity, estimated to represent a hiatus of up to 20 million years.
The Amin and Nimr units are both recognized in the sedimentary basins of north and south Oman, but they have widely differing properties. The Amin formation is a high-net-to-gross-ratio, continental succession deposited in alluvial-/fluvial-fan, sabkha (wet and dry), aeolian, and fluvial sheetflood/sand flat environments, generally with a high water table. The underlying Nimr group comprises two formations, a unit comprising fluvial and lacustrine/playa deposits overlain by a unit comprising large-scale coarsening-upward fluvial deposits.
New Operating Model
Past reservoir-characterization methods are no longer sufficient when appraising low-permeability gas reservoirs where performance is directly linked to reservoir quality and the effectiveness of the selected method of reservoir stimulation.
Several technologies have been applied recently in Oman to improve the understanding of tight gas opportunities, and these include the incorporation of advanced drilling practices; improved understanding of subsurface environment and hydraulic-fracturing design and methodology; hydraulic-fracturing evaluation; and well-completion considerations from a hydraulic-fracturing and subsequent-well-production standpoint.
In 2009 Petroleum Development Oman LLC (PDO) started an ambitious tight and deep gas exploration programme exploring for previously untapped reservoirs. The exploration strategy is focusing on both conventional tight gas plays as well as deep unconventional gas resources. These resources are typically in previously undrilled formations at great depths, with high temperatures and unknown pressure regimes, and uncertain fluid fill and composition. The unique geological properties of this type of reservoir require different strategies and technology deployment in order to make them viable and sustainable.
With unique geomechanical, reservoir, and geological properties, some of the large gas-bearing prospects within the Fahud Basin in the Sultanate of Oman require innovative drilling and completion practices. A revised drilling and completion workflow, with specific technology deployment and operational flexibility, has been developed in order to account for such reservoir complexity. This workflow includes the incorporation of rock strength acquisition and stress state of the reservoir prior to completion, in order to identify targets for hydraulic fracturing and quantify hydraulic fracturing performance versus reservoir deliverability. The unparalled challenges encountered whilst exploring for these resources required resolving to new technologies from outside the region and adapting them to local conditions.
This paper demonstrates the need of integrating various unconventional data sources to enhance the chance of successful reservoir characterization that leads to better understanding of presence of hydrocarbons and reservoir quality. It will also show that classical evaluation methods fail and will not lead to unambiguous interpretations. Recent experience has shown that several independent data sources need to be applied to confidently evaluate well results.
The successful application of a technology plan covering aspects of geomechanics, well completions, perforation and formation breakdown, hydraulic fracture placement and treatment yielded positive results that will be of interest to other regional operators facing similar challenges.
In May 2002, Petroleum Development Oman (PDO) embarked on a ten well, underbalanced drilling (UBD) trial campaign in the Nimr field using crude oil as the drilling fluid and membrane generated nitrogen as the lift gas. UBD was proposed as a productivity improvement technique for the Nimr field following a low risk/high reward analysis. The Nimr field is a complex of six fields. UBD was implemented in the Nimr A field consisting of two reservoirs: the Amin and Al Khlata, which are generally high permeability (±1Darcy) sandstone reservoirs containing medium gravity (21°API) viscous (300-500 cP) crude.
Horizontal wells are generally completed with a wire-wrap screen (WWS) across the reservoir section, due to sand production history in some wells, and are produced via artificial lift methods, primarily beam pump. Even though the predominant factor affecting net oil rate performance was the rate and behavior of water cut development it was suspected that drilling-induced skin, combined with mechanical skin from the completion, was a contributing factor to recent poor results from the horizontal wells.
The paper will demonstrate the value of a multi-well campaign to avoid eliminating a good candidate reservoir due to inconclusive start-up results associated introducing a new technology. It will describe some of these early start-up challenges, the equipment modifications and changes to operating procedures that have resulted in the uptake of this game-changing technology in the Nimr field. Additionally, it will emphasize the potential value of well inflow and reservoir characterization data gathered during UBD operations. This data indicated significant opportunities to improve well performance and increase ultimate recovery resulting in a potential value far exceeding those originally envisaged prior to initiating the UBD trial.