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Patil, Parimal A. (PETRONAS) | Chidambaram, Prasanna (PETRONAS) | Bin Ebining Amir, M Syafeeq (PETRONAS) | Tiwari, Pankaj K. (PETRONAS) | Das, Debasis P. (PETRONAS) | Picha, Mahesh S. (PETRONAS) | B A Hamid, M Khaidhir (PETRONAS) | Tewari, Raj Deo (PETRONAS)
Abstract Underground storage of CO2 in depleted gas reservoirs is a greenhouse gas reduction technique that significantly reduces CO2 released into the atmosphere. Three major depleted gas reservoirs in Central Luconia gas field, located offshore Sarawak, possess good geological characteristics needed to ensure long-term security for CO2 stored deep underground. Long-term integrity of all the wells drilled in these gas fields must be ensured in order to successfully keep the CO2 stored for decades/centuries into the future. Well integrity is often defined as the ability to contain fluids without significant leakage through the project lifecycle. In order to analyze the risk associated with all 38 drilled wells, that includes 11 plugged and abandoned (P&A) wells and 27 active wells, probabilistic risk assessment approach has been developed. This approach uses various leakage scenarios, that includes features, events, and processes (FEP). A P&A well in a depleted reservoir is a very complex system in order to assess the loss of containment as several scenarios and parameters associated to those scenarios are difficult to estimate. Based on the available data of P&A wells, a well has been selected for this study. All the barriers in the example well have been identified and properties associated with those barriers are defined in order to estimate the possible leakage pathways through the identified barriers within that well. Detailed mathematical models are provided for estimating CO2 leakage from reservoir to the surface through all possible leakage pathways. Sensitivity analysis has been carried out for critical parameters such as cement permeability, and length of cement plug, in order to assess the containment ability of that well and understand its impact on overall well integrity. Sensitivity analysis shows that permeability of the cement in the annulus, and length of cement plug in the wellbore along with pressure differential can be used as critical set of parameters to assess the risk associated with all wells in these three fields. Well integrity is defined as the ability of the composite system (cemented casings string) in the well to contain fluids without significant leakage from underground reservoir up to surface. It has been recognized as a key performance factor determining the viability of any CCS project. This is the first attempt in assessing Well Integrity risk related to CO2 storage in Central Luconia Gas Fields in Sarawak. The wells have been looked individually in order to make sure that integrity is maintained, and CO2 is contained underground for years to come.
Abstract Blowout Preventer (BOP) is mainly used to control well pressure by quick well shut in the event of overflow and well kick to prevent blowout on the rigs during drilling, completion, workover, and plug and abandonment phases of well operations. Regulators, Operators and Drilling contractors have put in place the requirement to test BOP systems as a method of inspection and assurance in this process safety critical steps. During well operations regular BOP pressure testing will need to be conducted to ensure its integrity and functionality as per testing requirement. In most cases BOP pressure testing is conducted online using rig time although it can also be conducted offline in some circumstances. BOP Pressure testing is considered flat time during well operations and the operators’ goal is to minimize flat times for rig time saving thus operating cost reduction. Flat time reduction can be achieved by reducing BOP pressure testing period and improving the efficiency in the entire testing process. As such a digital pressure testing system was deployed to multiple offshore drilling rigs in Malaysia beginning in September 2019 as innovative technological solutions. This paper represents the digital pressure testing system deployment study on both subsea and surface BOP drilling rigs for direct comparison with the process in use of the analog circular charter recorders (CCR) for BOP Pressure Testing. The study has shown an average 22% reduction in test times, improved safety, improved efficiency in recognizing failed tests faster, improved data reliability and repeatability of BOP pressure tests.
Abstract This paper highlights the efforts to mitigate the unprecedented situation of truncated gas demand via network modeling development and harmoniously harvesting value generation by its implementation. Global Pandemic in year 2020 resulted into unique situation of steep truncated gas demand due to economic slowdown worldwide. Hence as a prudent operator its deemed necessary to pursue strategic ideas and innovative concepts to manage offshore complex gas network to handle reduced supply demand balance, whilst protecting fulfill technical and contractual obligations also by optimizing value generation. It therefore demands the development and implementation of robust integrated system (end to end value chain system for hydrocarbon molecule) that would be leveraged on for agile response for deploying appropriate resolution considering dynamics of supply/demand balance and system equilibrium. This study focuses on a state of art that was commenced to develop an End to End Holistic Network Model from well head (fields) to product delivery terminal to scrutinize the complex offshore facilities to decipher appropriate pain points in terms of capabilities, risks, uncertainty, opportunity and exposures by performing robust analysis for trouble shooting, root cause analysis, gap analysis and expansion strategies for required scenario(s). A novel approach was influenced to create simulation model for complex network with building components i.e. source (100+ fields), sinks (multiple terminals), connectors (120+ export pipelines and ∼8 gas highways) along with pressure boosters (pump/compressor) etc. embedded in model. Major hubs, sub-hub, spill-over pipelines/loop lines including main gas transporting facilities with dedicated receiving terminal which formed integral part of network were also modeled in single platform. Flow co-relations for hydraulic estimations and material balance calculations along with engineering thermodynamics formulae for seamless data transfer in collaboration with operations were inbuilt for representative and resilient results. Simulation model was further validated with actual plant data as history matching and that precise forecasting analysis output. Multiple scenarios utilizing system ullage/ pipeline hydraulics (adhering to first principles) were studied and suitable alteration in operating philosophy e.g. were proposed to cater the truncated demand and to shape development strategies for future portfolios. Multi-level diagnostic was conducted to assure that system parameters such as operating pressure, velocity limits and required quality specifications are within operating envelope for the entire landscape. Lookahead analysis (what-if scenarios) were performed to evaluate to root cause analysis and troubleshoot at various intensities of the network to cater for equilibrium balance. Multiple contemplating scenarios were accomplished to analyze complex network parameters such as ullage opportunity, pressure variations, hydraulic fluxes, potential choking of low-pressure wells/fields & prospective blending specifications with variations in the supply/demand outlook. Gap analysis was executed in addition to arrive at necessary alterations for operating philosophy, partial segregation of system for pressure balancing due to low flow volume and product quality adherence. Model output assisted to gauge the potential for operating network by implementing appropriate reforms to optimize truncated flow in system and ensuring system is above its minimum turndown rate flow regime and could also propose to have the necessary mitigations to be in place for vigorous liquid management system due to low flow in network. Above methodology describes how by developing an end to end network model that summarize the granularity of a complex offshore network has facilitated to steer the agile response for operating envelope to cater the fluctuations in the demand/supply balance and optimize offshore allocations by network balancing for value maximization and to form a vision of portfolio strategy for future developments.
Abstract Natural gas is the noble fuel of 21st century. Consumption increased nearly 30% in last decade. Exploitation of conventional, unconventional, and contaminated gas resources are in focus to meet the demand. There are number of giant gas fields discovered worldwide and some of them with higher degree of contaminants viz. CO2, H2S and Hg. Additionally, they have operating challenges of high pressure and temperature. It becomes more complex when discovery is in offshore environment. This study presents the development and production, separation, transportation and identification & evaluation of storage sites and sequestration and MMV plan of a giant carbonate gas field in offshore Malaysia. Geological, Geophysical and petrophysical data used to describe the reservoir architecture, property distribution and spatial variation in more than 1000m thick gas bearing formation. Laboratory studies carried out to generate the rock and fluid representative SCAL (G-W), EOS and Supercritical CO2-brine relative permeability, geomechanics and geochemical data for recovery and storage estimates in simulation model and evaluating the post storage scenario. These data are critical in hydrocarbon gas prediction and firming up the number of development wells and in the simulation of CO2 storage depleted carbonate gas field. Important is to understand the mechanism in the target field for storage capacity, types of storage- structural and stratigraphic trapping, solubility trapping, residual trapping and mineral trapping. Study covers methodologies developed for minimization of hydrocarbon loss during contaminants separation and utilization of CO2 in usable products. Uncertainty and risk analysis have been carried out to have range of solution for production prediction and CO2 storage. Coupled Simulation studies predict the production plateau rate and 5 Tscf recovery separated contaminants profile and volume > one Tscf in order to have suitable geological structure for storage safely forever. Major uncertainties in the dynamic and coupled geomechanical-geochemical dynamic model has been captured and P90, P50, P10 forecast and storage rates and volumes have been calculated. Results includes advance methodologies of separation of hydrocarbon gas and CO2 like membrane and cryogenics for bulk separation of CO2 from raw gas and its transportation in liquid and supercritical form for storage. Study estimates components of sequestration mechanism, effect of heterogeneity on transport in porous media and height of stored CO2 in depleted reservoir and migration of plume vertically and horizontally. Generation of chemical product using separated CO2 for industrial use is highlighted.
Choudhary, Manish Kumar (Brunei Shell Petroleum Company Sendirian Berhad) | Mahanti, Gaurav (Brunei Shell Petroleum Company Sendirian Berhad) | Rana, Yogesh (Brunei Shell Petroleum Company Sendirian Berhad) | Garimella, Sai Venkata (Brunei Shell Petroleum Company Sendirian Berhad) | Ali, Arfan (Brunei Shell Petroleum Company Sendirian Berhad) | Li, Lin (Brunei Shell Petroleum Company Sendirian Berhad)
Abstract Field X is one of largest oil fields in Brunei producing since 1970's. The field consists of a large faulted anticlinal structure of shallow marine Miocene sediments. The field has over 500 compartments and is produced under waterflood since 1980's through 400+ conduits over 50 platforms. A comprehensive review of water injection performance was attempted in 2019 to assess remaining oil and identify infill opportunities. Large uncertainties in reservoir properties, connectivity and fluid contacts required that data across multiple disciplines is integrated to identify new opportunities. It was recognized early on that integrated analysis of surveillance data and production history over 40 years will be critical for understanding field performance. Hence, reviews were first initiated using sand maps and analytical techniques. Tracer surveys, reservoir pressures, salinity measurements, Production Logging Tool (PLT) were all analyzed to understand waterflood progression and to define connectivity scenarios. A complete review of well logs, core data from over 30 wells and outcrop studies was carried out as part of modelling workflow. This understanding was used to construct a new facies-based static model. In parallel, key dynamic inputs like PVT analysis reports and special core analysis studies were analyzed to update dynamic modelling components. Prior to initiating the full field model history matching, a comprehensive impact analysis of the key dynamic uncertainties i.e., Production allocation, connectivity and varying aquifer strength etc. were conducted. An Assisted History Matching (AHM) workflow was attempted, which helped in identifying high impacting inputs which could be varied for history matching. Adjoint techniques were also used to identify other plausible geological scenarios. The integrated review helped in identifying over 50 new opportunities which potentially can increase recovery by over 10%. The new static model identified upsides in Stock Tank Oil Initially in Place (STOIIP) which if realized could further increase ultimate recoverable. The use of AHM assisted in reducing iterations and achieve multiple history matched models, which can be used to quantify forecast uncertainty. The new opportunities have helped to revitalize the mature field and has potential to almost increase the production by over 50%. A dedicated team is now maturing these opportunities. The robust methodology of integrating surveillance data with simulation modelling as described in this paper is generic and could be useful in current day brown field development practices to serve as an effective and economic manner for sustaining oil production and maximizing ultimate recovery. It is essential that all surveillance and production history data are well analyzed together prior to attempting any detailed modelling exercise. New models should then be constructed which confirm to the surveillance information and capture reservoir uncertainties. In large oil fields with long production history with allocation uncertainties, it is always a challenge for a quantitative assessment of History match quality and infill well Ultimate Recovery (UR) estimations. Hence a composite History Match Quality Indicator (HMQI) was designed with an appropriate weightage of rate, cumulative & reservoir pressure mismatch, water breakthrough timing delays. Then HMQI parameter spatial variation maps were made for different zones over the entire field for understanding and appropriately discounting each infill well oil recovery. Also, it is critical that facies variation is properly captured in models to better understand waterfront movements and locate remaining oil. Dynamic modelling of mature field with long production history can be quite challenging on its own and it is imperative that new numerical techniques are used to increase efficiency.
Md Yusof, Muhammad Aslam (Universiti Teknologi PETRONAS) | Ibrahim, Mohamad Arif (Universiti Teknologi Malaysia) | Mohamed, Muhammad Azfar (Universiti Teknologi PETRONAS) | Md Akhir, Nur Asyraf (Universiti Teknologi PETRONAS) | M Saaid, Ismail (Universiti Teknologi PETRONAS) | Ziaudin Ahamed, Muhammad Nabil (Universiti Teknologi PETRONAS) | Idris, Ahmad Kamal (Universiti Teknologi Malaysia) | Awangku Matali, Awangku Alizul (Vestigo Petroleum)
Abstract Recent studies indicated that reactive interactions between carbon dioxide (CO2), brine, and rock during CO2 sequestration can cause salt precipitation and fines migration. These mechanisms can severely impair the permeability of sandstone which directly affect the injectivity of supercritical CO2 (scCO2). Previous CO2 injectivity change models are ascribed by porosity change due to salt precipitation without considering the alteration contributed by the migration of particles. Therefore, this paper presents the application of response surface methodology to predict the CO2 injectivity change resulting from the combination of salt precipitation and fines migration. The impacts of independent and combined interactions between CO2, brine, and rock parameters were also evaluated by injecting scCO2 into brine saturated sandstone. The core samples were saturated with NaCl brine with salinity between 6,000 ppm to 100,000 ppm. The 0.1, 0.3, and 0.5 wt.% of different-sized hydrophilic silicon dioxide particles (0.005, 0.015, and 0.060 μm) were added to evaluate the effect of fines migration on CO2 injectivity alteration. The pressure drop profiles were recorded throughout the injection process and the CO2 injectivity alteration was represented by the ratio between the initial and final injectivity. The experimental results showed that brine salinity has a greater individual influence on permeability reduction as compared to the influence of particles (jamming ratio and particle concentration) and scCO2 injection flow rate. Moreover, the presence of both fines migration and salt precipitation during CO2 injection was also found to intensify the permeability reduction by 10%, and reaching up to threefold with increasing brine salinity and particle size. The most significant reductions in permeability were observed at higher brine salinities, as more salts are being precipitated out which, in turn, reduces the available pore spaces and leads to a higher jamming ratio. Thus, more particles were blocked and plugged especially at the slimmer pore throats. Based on comprehensive 45 core flooding experimental data, the newly developed model was able to capture a precise correlation between four input variables (brine salinity, injection flow rate, jamming ratio, and particle concentration) and CO2 injectivity changes. The relationship was also statistically validated with reported data from five case studies.
Yu, Jingfeng (PetroChina Xinjiang Oilfield Company) | Zhou, Diao (PetroChina Xinjiang Oilfield Company) | Zhang, Bo (PetroChina Xinjiang Oilfield Company) | Meng, Haiping (PetroChina Xinjiang Oilfield Company) | Li, Tong (Schlumberger) | Wang, Li (Schlumberger) | Wang, Yong (Schlumberger) | Wang, Fei (Schlumberger) | Wang, Chao (Schlumberger) | Chen, Chengqian (Schlumberger) | Hu, Zhong (Schlumberger) | Lan, Wencheng (Schlumberger) | Liu, Guoyu (Schlumberger) | Wang, Shuai (Schlumberger)
Abstract MH oilfield is a fan delta deposited unconventional tight oil reservoir with complex lithology of volcanic rocks, metamorphic rocks, conglomerate, and claystone. The drilling efficiency was optimized by using the first-generation boundary mapping technology with Rotary Steering System (RSS) during the first batch drilling campaign (H2-2016∼H1-2017), which was mentioned in IADC/SPE-190998-MS. But with the development going further, more and more wells drilled into shale interbed causing low pay zone exposure, long drilling duration, and numerous drilling hazards. The overall drilling performance was not optimistic as before, the average Rate Of Penetration (ROP) decreased by 30.7% and the average footage per run decreased by 38.9% during horizontal section operation in some specific blocks of MH oilfield. By reviewing the detailed drilling and geology material of the first batch drilling, the challenges were defined. There is lateral irregular thin shale interbed existing in this conglomeratic reservoir which is rarely observed from the nearby wells in the first batch drilling zone. That unstable shale interbed with 0.5-2m thickness isolated the target into 2 to 3 components. The first-generation boundary mapping technology can only detect the nearest up or down boundary, with this limitation, it is difficult to reveal these laterally unstable shale interbed. It is crucial to precisely delineate the irregular thin interbed to develop this complex reservoir. Meanwhile, the bit selection which didn't catch up with the formation change is another issue that needs to be optimized timely. To solve the above challenges, the new generation boundary mapping while drilling technology was introduced to this project, it has 3 or more boundaries detecting ability at the same time, which can delineate the irregular thin interbed and optimize real-time Well Placement decision making. Meanwhile, the bit design and selection based on the timely geological data interpretation helped to improve drilling efficiency. This innovative integrated method deployed in phase II horizontal well drilling campaign proved to be an effective approach to optimize geosteering and drilling performance. The clear reservoir geometry delineation effectively helps avoid entering the irregular shale interbed in real-time, thus improve the pay zone exposure and trajectory smoothness. Till 2018, more than 50 wells were completed, the overall drilling performance of 2018 has been improved by 47.2% of footage per run and 42.2% of ROP compared with statistical results of H2-2017 of the M131 block and nearly back to the normal level. In this paper, the authors will demonstrate how this integrated approach helps optimize Well Placement, enhance drilling efficiency and save budget with some exemplary case studies. With this success, the authors believe this approach and techniques could effectively address the following horizontal well drilling campaign in this unconventional tight oil reservoir.
Xu, Wei (China University of Geosciences, Beijing) | Fang, Lei (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.) | Guo, Fuxin (CNOOC Research Institute Co., Ltd.) | Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Chen, Kaiyuan (China University of Geosciences, Beijing)
Abstract Reservoir prediction is a core area of research in oilfield exploration and development, and it is generally constructed on a combination of well data, seismic attributes or inversion. However, reservoir prediction in sparse well areas poses great challenges due to insufficient well control. If the quality of seismic data is poor, the spatial distribution characteristics of reservoirs cannot be effectively characterized through inversion or attribute analysis, which seriously affects the prediction accuracy. This paper proposes a new method to solve the difficulty in reservoir prediction of oilfields with sparse data and poor quality seismic cube, which evolves from depositional models, forward stratigraphic modeling (FSM) to geocellular modeling. First, based on the comprehensive analysis of core, seismic, grain size, heavy minerals, dip data, it is believed that a special fan delta developed in the Miocene strata in the south of Albert Basin. The reservoirs are dominated by distributary channels, which are in medium-coarse grains, and the provenance is from the southwest to flowing to the northeast. The formation thickness of the stratum decreases from the boundary fault to the direction of the basin. Then, the input parameters of FSM modeling are quantitatively expressed based on the sedimentary model research, including model boundary conditions, basic input information, sediment supply and transportation. FSM results were used to quantitatively characterize the deposition process. The FSM simulation results are compared with the depositional model and well data to verify the reliability. Finally, the shale content model in FSM results is resampled to the geocellular grids and used as the constraint for facies model and property model in geological modeling. This model is used for well pattern design and optimization. This new approach integrates the conceptual depositional model with quantitative FSM results. It improves the accuracy of reservoir prediction and provides a new technical workflow for reservoir characterization. Furthermore, it helps to obtain more insight into the sedimentary process and reduces the risk of oilfield exploration and development.
Abstract In a difficult situation where the oil market is down, reducing drilling cost is always an interesting outlook to be pursued. To do so, one should consider looking at the highest component on the drilling cost. Down-hole equipment failure and stuck pipe is avoidable during the engineering planning. It is well-known that billions of dollars have been lost and numerous Bottom-Hole Assembly (BHA) are left in the well due to such problems, related to stick-slip phenomenon. Thus, despite the low oil price, it is a new normal that some asset owners opt to invest on high-end tools to prevent stick-slip, meanwhile others are still reluctant because of its high initial costs and chose to solely focus on the technical skills to drill faster. The objective of this paper is to determine whether, and which, utilization of these automations will be an effective method to lower overall cost, between using Anti-Stick Slip Technology (AST), Surface soft-torque, Self-Adjusting PDC Bit or all three combined together. The analysis of this project is conducted by providing conjecture in comparative method to visualize the configuration. In each case, estimated Rate of Penetration (ROP) is observed based on the recent literature of its application in similar lithology which is carbonate and interbedded shale. As the ROP increases, the overall drilling cost along with percentage of potential net saving for each case is evaluated in this study and select the most effective strategy. The outturn suggests that despite the high initial investment, combining all technologies are economically advantaged. With the DOCC by the self-adjusting PDC bit and torque alleviation by AST to handle the rock interface in addition to BHA torque wave mitigation from surface by surface soft torque, the ROP is quantified as summation of all cases’ ROP gained as the tool complements each other. The estimated ROP of the case significantly gives high decrement of the overall cost and boosted the potential net saving. Moreover, prevention from NPT due to downhole failure and stuck pipe problem is also a contributing factor to increasing cost efficiency. Therefore, combining all the tool together is proven to be the most favorable option aside from, respectively from preferable to the less, utilizing Surface Soft Torque, Self-Adjusting PDC Bit, and AST. Although it requires high initial investment, it is worthwhile to explore the usage of automation technologies for the overall cost reduction contributes to make the case financially attractive.
Abstract The use of micronized weighting agents, in multiple operations, have become more commonplace over the years, with current applications now going far beyond their targeted original purpose of reducing pressure losses in extended reach wells. This specific case reports the development of a fit for purpose system engineered to tackle multiple challenges such as: limitation in using heavy density brines composed of bromides in an offshore environment; hydrate suppression under Drill Stem Test (DST) conditions; weighting agent sagging control; plugging of downhole tools due to heavy solids loading; proper pressure transmission for downhole tools activation; and formation damage prevention. The operation involved the following steps: 1 - development of a Water-based Micronized Weighting Agent Fluid System (WBMWAFS), laboratory testing, simulation evaluation and testing validation for all target properties; 2 - development of an appropriate DST approach with the usage of a designed set of explosives to minimize formation damage and the interaction of the DST fluid with such cargos; and 3 - the evaluation of the overall system performance in order to validate the integrated approach used to design such solution. The DST results indicated that the WBMWAFS is capable of delivering all the technical requirements for a trouble-free operation, with no significant register of weighting agent sag, hydrates or with any variation in fluid properties, whilst enabling a DST operation that demonstrated a negative skin damage during the clean-up period and no damage associated with the WBMWAFS. The WBMWAFS performance opens the possibility of the application of this type of fluid as a replacement for high-density clear brines in many challenging environments.