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Abstract Efficient multistage hydraulic fracturing in horizontal wells in tight-gas formations with multilayered and laminated reservoirs is a very challenging subject matter; due to formation structure, required well trajectory, and the ability to establish a conductive and permanent connection between all the layers. BP Oman had initiated the technical journey to deliver an effective horizontal well multistage frac design through learnings obtained during three key pilot horizontal wells. Since these initial wells, additional candidates have been drilled and stimulated, resulting in further advancement of the learning curve. Many aspects will be covered in this paper, that will describe how to facilitate the most effective hydraulic fracture placement and production performance, under these laminated conditions. These approaches will include the completion and perforation selection, fracture initiation zone selection, fracture height consideration, frac fluid type and design. The paper will go on to describe a range of different surveillance options, including clean-up and performance surveillance as well as number of other factors. The experiences that have been gained provide valuable insight and learning about how to approach a multistage fracturing horizontal well program in this kind of depositional environment. Additionally, how these lessons can potentially be subsequently adapted and applied to access resources in the more challenging and higher risk areas of the field. For example, this paper will present direct comparison of over and under-displaced stages; differences in execution and production for cased hole and open hole completions; and many other variables that always under discussion for hydraulic fracturing in horizontal wells. This paper describes in detail the results of many multistage fracturing trials by BP Oman in horizontal wells drilled in challenging multilayered and laminated tight-gas reservoirs. These findings may help to cut short learning curve in similar reservoirs in the Middle East Region and elsewhere.
Shaoul, Josef R. (Fenix Consulting Delft) | Park, Jason (Fenix Consulting Delft) | Boucher, Andrew (Fenix Consulting Delft) | Tkachuk, Inna (Fenix Consulting Delft) | Veeken, Cornelis (Petroleum Development Oman) | Salmi, Suleiman (Petroleum Development Oman) | Bahri, Khalfan (Petroleum Development Oman) | Rashdi, Mohammed (Petroleum Development Oman) | Nazaruk, Dariusz (Petroleum Development Oman)
Abstract The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020. The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity. Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel. Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.
Abstract This paper describes the journey of hydraulic fracturing design solutions and implementation in Khazzan field. More than 100 wells have been stimulated with hydraulic fracturing in the field in the last decade. Most of these wells were treated with a single-stage massive propped hydraulic fracturing treatment aimed at stimulating the entire vertical productive zone in a single treatment. More recently, hydraulic fracturing has begun on the southern acreage from Khazzan, referred to as Ghazeer. Producing layers in this area are thicker and higher permeability and, as a result, more prolific. Based on the available data and experiences, the establishment of clear guidelines has become a requirement to help the understanding and adjust the hydraulic fracturing design for each well to be become a well-specific optimum design. During the stimulation journey, surveillance techniques have been utilized and implemented in the Khazzan and Ghazeer fields to provide and develop better understanding of the fracture propagation process. These data have proven essential to support stimulation design evolvement and determine if multiple fracturing stages are justified or whether a single stage would be sufficient. Based on a wide range of hydraulic fracture stimulation operations performed across the Khazzan and Ghazeer fields, a flowchart was developed to integrate all the lessons learned from the previous experience and help optimize future fracture design. Clear guidelines include the rationale between the selection of single or multiple fracturing stages, the selection of optimal pad fractions, and other associated details of the fracture design. This flowchart has been extensively validated with surveillance and has proven its inherent value in many stimulated wells, with either single or multiple proppant fracturing stages.
Abstract Hydraulic Fracturing (HF) is widely used in PDO in low permeability tight gas formations to enhance production. The application of HF has been expanded to the Oil South as conventional practice in enhancing the recovery and production at lower cost. HF stimulation is used in a number of prospects in the south Oman, targeting sandstone formations such as Gharif, Al Khlata, Karim and Khaleel, most of which have undergone depletion. Fracture dimension are influenced by a combination of operational, well design and subsurface parameters such as injected fluid properties, injection rate, well inclination and azimuth, rock mechanical properties, formation stresses (i.e. fracture pressures) etc. Accurate fracture pressure estimate in HF design and modeling improves reliability of HF placement, which is the key for improved production performance of HF. HF treatments in the studied fields provide large volumes of valuable data. Developing standardized tables and charts can streamline the process to generate input parameters for HF modeling and design in an efficient and consistent manner. Results of the study can assist with developing guidelines and workflow and for HF operations. Field HF data from more than 100 wells in south Oman fields were analyzed to derive the magnitude of breakdown pressure (BP), Fracture Breakdown Pressure (FBP), Instantaneous Shut-In Pressure (ISIP) pressure, and Fracture Closure Pressure (FCP) and develop input correlations for HF design. Estimated initial FCP (in-situ pore pressure conditions) is in the range of 15.6 - 16 kPa/mTVD at reservoir formation pressure gradient of about 10.8 kPa/m TVD bdf. However, most of the fields have undergone variable degree of depletion prior to the HF operation. Horizontal stresses in the reservoir decrease with depletion, it is therefore important to assess the reduction of FCP with reduction in pore pressure (stress depletion). Depletion stress path coefficient (i.e. change on FCP as a fraction of change in pore pressure) was derived based on historic field data and used to predict reduction of FCP as a function of future depletion. Data from this field indicates that the magnitude of decrease in fracture pressure is about 50% of the pore pressure change. Based on the data analysis of available HF data, standardized charts and tables were developed to estimate FCP, FBP, and ISIP values. Ratios of FBP and ISIP to FCP were computed to establish trend with depth to provide inputs to HF planning and design. Results indicate FBP/FCP ratio ranges between 1.24-1.35 and ISIP/FCP ratio ranges between 1.1 to 1.2. Developed workflow and standardized tables, charts and trends provide reliable predictions inputs for HF modeling and design. Incorporating these data can be leveraged to optimize parameters for HF design and modeling for future wells.
Abstract The tight gas reservoirs of Haima Supergroup provide the majority of gas production in the Sultanate of Oman. The paper discusses a possibility of using the anomalies from natural radioactivity to evaluate the fracture height for complex tight gas in mature fields of Oman. The standard industry practice is adding radioactive isotopes to the proppant. Spectral Gamma Ray log is used to determine near wellbore traced proppant placement. Spectral Noise log in combination with Production logs helps to identify the active fractures contributing to production. These methods complement each other, but they are obviously associated with costs. Hence, majority of wells are fracced without tracers or any other fracture height diagnostics. However, in several brown fields, an alternative approach to identify fracture height has been developed which provides fit-for-purpose results. It is based on the analysis of naturally occurring radioactive minerals (NORM) precipitation. The anomalies were observed in the many gas reservoirs even in cases when tracers were not used. At certain conditions, these anomalies can be used to characterize fracture propagation and optimize future wells hydraulic Fracture design. A high number of PLTs and well test information were analyzed. Since tight formations normally don't produce without fracturing, radioactive anomalies flag the contributing intervals and hence fracture propagation. The main element of analysis procedure is related to that fact that if no tracers applied, the discrepancy between normalized Open Hole Gamma Ray and Gamma Ray taken during PLT after 6-12 months of production can be used instead to establish fracture height. This method cannot be applied for immediate interpretation of fracture propagation because time is required to precipitate NORM and using the anomalies concept. The advantage of this method is that it can be used in some fields to estimate the frac effectiveness of wells without artificial tracers. It is normally assumed that the Natural radioactivity anomalies appear mainly due to co-production of the formation water. However, in the fields of interest the anomalies appear in wells producing only gas and condensate. This observation provides an opportunity for active fracture height determination at minimum cost.
Veeken, Cornelis Adrianus (Petroleum Development Oman) | Busaidi, Yousuf (Petroleum Development Oman) | Hajri, Amira (Petroleum Development Oman) | Hegazy, Ahmed Mohammed (Petroleum Development Oman) | Riyami, Hamyar (Petroleum Development Oman) | Rashdi, Mohammed (Petroleum Development Oman) | Zarafi, Mohammed (Petroleum Development Oman) | Zadjali, Mohammed (Petroleum Development Oman) | Darga, Kumaresh (Petroleum Development Oman) | Mamari, Mazen (Ministry of Energy and Minerals)
Abstract PDO operates about 200 deep gas wells in the X field in the Sultanate of Oman, producing commingled from the Barik gas-condensate and Miqrat lean gas reservoir completed by multiple hydraulic fracturing. Their inflow performance relation (IPR) is tracked to diagnose condensate damage, hydraulic fracture cleanup and differential reservoir pressure depletion. The best IPR data is collected through multi-rate production logging but surface production data serves as an alternative. This paper describes the process of deriving IPR's from production logging and surface production data, and then evaluates 20 years of historic IPR data to quantify the impact of condensate damage and condensate cleanup with progressive reservoir pressure depletion, to demonstrate the massive damage and slow cleanup of hydraulic fractures placed in depleted reservoirs, to show how hydraulic fractures facilitate the vertical cross-flow between isolated reservoir intervals, and to highlight that stress-dependent permeability does not play a major role in this field.
Abstract The scope of this work is to measure downhole fracture-initiation pressures in multiple carbonate reservoirs located onshore about 50 km from Abu Dhabi city. The objective of characterizing formation breakdown across several reservoirs is to quantify the maximum gas and CO2 injection capacity on each reservoir layer for pressure maintenance and enhance oil recovery operations. This study also acquires pore pressure and fracture closure pressure measurements for calibrating the geomechanical in-situ stress model and far-field lateral strain boundary conditions. Several single-probe pressure drawdown and straddle packer microfrac injection tests provide accurate downhole measurements of reservoir pore pressure, fracture initiation, reopening and fracture closure pressures. These tests are achieved using a wireline or pipe-conveyed straddle packer logging tool capable to isolate 3 feet of openhole formation in a vertical pilot hole across five Lower Cretaceous carbonate reservoirs zones. The fracture closure pressures are obtained from three decline methods during the pressure fall-off after fracture propagation injection cycle. The three methods are: (1) square-root of the shut-in time, (2) G-Function pressure derivative, and (3) Log-Log pressure derivative. The far-field strain values are estimated by multi-variable regression from the microfrac test data and the core-calibrated static elastic properties of the formations where the stress tests are done. The reservoir pressure across these carbonate formations are between 0.48 to 0.5 psi/ft with a value repeatability of 0.05 psi among build-up tests and 0.05 psi/min of pressure stability. The formation breakdown pressures are obtained between 0.97 and 1.12 psi/ft over 5,500 psi above hydrostatic pressure. The in-situ fracture closure measurements provide the magnitude of the minimum horizontal stress 0.74 - 0.83 psi/ft which is used to back-calculate the lateral strain values (0.15 and 0.72 mStrain) as far-field boundary condition for subsequent geomechanical modeling. These measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO2 injection capacity for effective enhance oil recovery within these reservoirs. This in-situ stress wellbore data represents the first of its kind in the field allowing petroleum and reservoir engineers to optimize the subsurface injection plans for efficient field developing.
Zhu, Dawei (RIPED,CNPC) | Cui, Mingyue (RIPED,CNPC) | Chen, Yandong (Halfaya Oil Co.) | Wang, Yongli (Halfaya Oil Co.) | Ding, Yunhong (RIPED,CNPC) | Xiong, Chunming (RIPED,CNPC) | Liang, Chong (RIPED,CNPC) | Yao, Fei (RIPED,CNPC) | Wang, Xiaoyong (Halfaya Oil Co.) | Cai, Wenxin (Halfaya Oil Co.) | He, Yanhui (Halfaya Oil Co.) | Ling, Zongfa (Halfaya Oil Co.) | Wang, Dayong (Antonoil Co.)
Abstract The carbonate reservoir S is a giant limestone reservoir in H Oilfield, Iraq. Although the reserves account for 25%, the production contribution is only 0.4% to the total oilfield production due to poor petrophysical properties. Accordingly, the first proppant fracturing on vertical well was successfully executed in December 2016, which has already achieved a steady production period over than 3 years. In order to further improve the productivity, the first multi-stage proppant fracturing(MSPF) on horizontal well(SH01X) was successfully applied in November 2019, a technique which is rarely reported for porous limestone reservoir in the Middle East. Proppant fracturing in carbonate reservoirs is a technique difficulty worldwide, especially this is a lack of experiences in the Middle East. To ensure the success of this campaign, a holistic technical study including geology evaluation, reservoir performance analysis, drilling trajectory design, completion and fracturing technique design have been carried out based on principle of "geology-engineering integration". This paper will present a comprehensive illustration including treatment design (main completion-fracturing technique, total scale, fracturing fluid, proppant), job execution (mini-frac, main-frac) and post-frac production performance for this successful campaign. True vertical depth (TVD) of Well SH01X is 2720 m and the horizontal section length is 811 m. Based on the main technique of multi-stage proppant fracturing with open hole packers and sliding sleeves, totally 3784.3 m fracturing fluid and 452 m proppant were pumped in 8 stages. The test production was 3214 BOPD (choke size: 40/64", wellhead pressure: 970 psi). A historical breakthrough in the productivity of S reservoir has been achieved by the campaign. The post-frac evaluation shows that the treatment parameters are consistent with the design. The connectivity between artificial fractures and formation is greatly improved, and the stimulation effect is significant. Currently the "production under controlled pressure" mode has been executed and the stable production under stimulation target rate has been maintained. The systematic "geology-engineering integration" workflow is of significance to the success of the treatment as well as the stimulation effect. MSPF is planned to be a game-changing technique to develop the huge reserves of S reservoir. The experience gained from this case could provide theoretical as well as practical references for similar reservoirs in the Middle East.
Abstract An accurate Mechanical Earth Model (MEM) is of vital importance in tight gas reservoirs where hydraulic fracturing is the only way to produce hydrocarbons economically. The Barik tight gas reservoir is the main target in Khazzan and Ghazeer Fields at the Sultanate of Oman (Rylance et al., 2011). This reservoir consists of multiple low-permeability sandstone layers interbedded with marine shales. A good understanding of the fracture propagation in such a reservoir has a major effect on completion and fracturing design. The MEM derived from sonic logs and calibrated with core data needs to be further validated by independent measurements of the fracturing geometry. Multiple surveillance techniques have been implemented in the Barik reservoir to validate the MEM and to match observations from hydraulic fracturing operations. These techniques include closure interpretation using a wireline deployed formation testing assembly, the use of mini-frac injection tests with deployed bottomhole pressure gauges, execution of post injection time-lapse temperature logging, the injection of radioactive tracers, associated production logging, subsequent pressure transient analysis and other techniques. A cross-disciplinary team worked with multiple sources of data to calibrate the MEM with the purpose of delivering a high-confidence prediction of the created fracture geometry, which honors all available surveillance data. In turn, this validation approach provided a solid basis for optimization of the completion and fracturing design, in order to optimally exploit this challenging reservoir and maximize the economic returns being delivered. For example, combination of stress testing with radioactive tracers provided confidence in stress barriers in this multilayered reservoir. Pressure transient analysis allowed to calibrate mechanical model to match fracturing half-length that is contributing to production. This paper provides extensive surveillance examples and workflows for data analysis. Surveillance of this degree in the same well is uncommon because of the associated time and cost. However, it provides unique value for understanding the target reservoir. This paper demonstrates the Value Of Information (VOI) that can be associated with such surveillance and provides a concrete and practical example that can be used for the justification of future surveillance programs associated with the hydraulic fracturing operations.
Abstract Development of the tight gas Khazzan Field in Sultanate of Oman has progressed through an extensive learning curve over many years. Thereby, the hydraulic fracturing design was fine-tuned and optimized to properly fit the requirements of the challenging Barik reservoir in this area. In 2018, BP Oman started developing the Barik reservoir in the Ghazeer Field, which naturally extends the reservoir boundary south of Khazzan Field. However, the Barik reservoir in the Ghazeer area is thicker and more permeable than in the Khazzan Field; therefore, the hydraulic fracturing design required adjustment to be optimized to directly reflect the reservoir needs of the Ghazeer Field. A comprehensive hydraulic fracturing design software was used for this optimization study and sensitivity analysis. This software is a plug-in to a benchmark exploration and production software platform and provides a complete fracturing optimization loop from hydraulic fracturing design sensitivity modelled with a calibrated mechanical earth model to detailed production prediction using the incorporated reservoir simulator. One of the stimulated wells from Ghazeer Field was used as the reference for this study. The reservoir sector model was created and adjusted to match actual data from this well. The data include fracturing treatment execution response, surveillance data such as radioactive tracers, bottomhole pressure gauge, and pressure transient analysis. Reservoir properties were also adjusted to match long-term production data obtained for this reference well. After the reservoir model was fully validated against actual data, multiple completion and fracturing scenarios were simulated to estimate potential production gain and thus find an optimal hydraulic fracturing design for Ghazeer Field. Many valuable outcomes can be concluded from this study. The optimal treatment design was identified. The value of fracture half-length versus conductivity was clarified for this area. The comparison between single-stage fracturing versus multistage treatment across the thick laminated Barik reservoir in a conventional vertical well was derived. The drainage of different layers with variable reservoir properties was compared for a range of different scenarios.