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Abstract With this paper, we demonstrate how CoreDNA, a trans-disciplinary suite of high-resolution, non-destructive measurements performed on whole cores at the onset of core analysis programs, helps operation geologists and petrophysicists with an innovative, cost effective and objective way to characterize the reservoir quality of highly laminated hydrocarbon-bearing formations where the standard practice (systematic plugging every foot) fails to provide a correct estimate. The case study focuses on core data from three wells intersecting formations characterized by very thin (millimetre-scale) sand and clay/silt laminations where the resolution of conventional wireline and lab gamma ray logs were not sufficiently sharp for an effective evaluation of reservoir quality. Although a high volume of routine core analysis data was already available for these wells, the remaining uncertainty on reservoir evaluation was deemed high enough by the study team to motivate the acquisition of additional data comprising ultra-high resolution pictures (1.8μm/px) and topographic maps created from micron-accurate laser scans. We explain how continuous profiles of grain size indicators could be used for the prediction of permeability variations across these laminated formations and for the definition of a permeability cut-off for the identification of poor vs good reservoir ratios compatible with the reservoir characteristics. CoreDNA test procedures are specifically designed to greatly accelerate the deliverables of core analysis, so that petrophysical evaluation may start right from the moment cores arrive from the well site, which is usually month before routine core analysis results are known. In the context of this paper, CoreDNA results were confirmed a-posteriori by the permeability measured on plugs samples from the two first wells. In the third well however, some marked differences were observed: although permeability ranges were found similar by the two methods, the distribution of permeability values obtained from routine core analysis conducted according to standard guidelines (one sample per foot) gave a more optimistic picture of permeability (90% rock above the 1mD cut-off) than the alternative approach based on high resolution continuous grain size data (70% rock above the 1mD cut-off). From the above findings, we conclude that a standard 1-ft interval for plug acquisition is not enough to fully characterise the distribution of permeability in highly laminated formations. Alternatively, a continuous profile of permeability index based on high resolution grain size measurements offers a fast and cost-efficient solution to obtain representative reservoir quality data, which enable objective well and reservoir management decisions few days after barrel opening without compromising core integrity for further studies.
The last year has seen people in many sectors unexpectedly confronting a new challenge--working remotely. Even before this, our industry has been trying to operate fields remotely (either partially or fully) and make operations smarter and more automated. Key drivers are to improve safety in operations, maximize production, and make operations more efficient. These efforts have been enabled by the rapidly changing technology landscape--in sophisticated acquisition and analysis of data and increased connectivity (from both fiber-optic and cellular networks). It also has been accelerated by the push across the industry to digitalize.
Malaysia's Petronas this week added another first to its list of accomplishments in pioneering LNG production using floating (FLNG) technology. Petronas became the first global energy company to own and produce from two floating LNG (FLNG) facilities, following the successful first shipping of LNG from its PFLNG DUA facility on 24 March. The Seri Camar LNG carrier transported the cargo to Thailand. PFLNG DUA works in deep water and can reach gas fields in water depths of up to 1500 m; its capacity is 1.5 mtpa of LNG. It passed subsea commissioning and produced first LNG in February.
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.
Noordin, M. Farriz (PETRONAS) | James Berok, Sylvia Mavis (PETRONAS) | Sinanan, Haydn Brent (PETRONAS) | Suratman, M. Farhan (PETRONAS) | Fabian, Oka (PETRONAS) | Mohammad, M. Afzan (PETRONAS) | Johari, M. Raimi (Marubeni-Itochu Tubulars Asia Pte Ltd)
Abstract PETRONAS has undertaken a large EOR project offshore Malaysia involving the use of Immiscible Water-Alternating-Gas (iWAG) wells for fluid injection. These iWAG injection wells will allow the alternate injection of both treated seawater and hydrocarbon gas. A significant concern for these wells is tubing corrosion resistance and integrity for over a 25-year injection life. The initial conceptual design for the iWAG injection tubing utilized Glass Reinforced Epoxy (GRE) & 25Cr tubing material due to the presence of dissolved oxygen in the injected water. The use of these materials present challenges due to limitations in downhole flow device installation with the GRE tubing and high cost of 25Cr tubing. The project team searched for alternative, fit for purpose materials to meet the project's requirements. Based on the recent PETRONAS success case of 17Cr utilization, the team examined the possibility of using 17Cr or lower grade CRA material for injection purposes. By pioneering the first application of 15Cr OCTG as an iWAG injection tubing material in the world, several risks had to be considered. Additionally, all risks had to be mitigated via various approaches ranging from detailed engineering planning to field execution and operation. The process of selecting this metallurgy involved criteria such as cost, performance, manufacturability and operational execution. The selection methodology included a comprehensive evaluation and recommendation process that consisted of: Evaluation of currently used metallurgical properties and limitations Identification of alternatives based on operating conditions, cost and manufacturing constraints Metallurgy qualification through comprehensive laboratory testing. Conducting tubing installation risk analysis Reviewing tubing operational, intervention and abandonment scenarios throughout the well life cycle The successful selection and installation of 15Cr was attributed to: The metallurgy selection, tubing procurement and installation process involving multidisciplinary and multifunctional groups both internal and external to PETRONAS. Rigorous testing at two separate laboratory facilities yielding test results which met and exceeded the required performance criteria. A 15Cr tubing make up efficiency of 100%. Impressive performance during operations resulting in a gross running speed of 371 ft/hr versus an average pipe running speed of 810 ft/hr. Use of low penetration dies to prevent slippage during tubing connection make up. This was critical since CRA material is very sensitive to scratching during contact with metal equipment. This potential metal scratching can lead to corrosion. On time delivery of 15Cr tubing from the OCTG provider ensuring sufficient time for preparation of completion accessories prior to offshore load out. Utilization of 15Cr as an alternative to Duplex and Glass Reinforced Epoxy (GRE) materials has also contributed a direct cost saving of 27% to the project.
Bela, Sunanda Magna (PETRONAS) | B Ahmad Mahdzan, Abdil Adzeem (PETRONAS) | A Rashid, Noor Hidayah (PETRONAS) | A Kadir, Zairi (PETRONAS) | Abu Bakar, Azfar Israa (PETRONAS) | Kamarudzaman, Zayful Hasrin (PETRONAS) | W Hasan, W Helmi (PETRONAS) | B M Nor, M Abshar (PETRONAS) | M Aziss, M Yusof (PETRONAS) | Tham, Khai Lun (Halliburton) | Arumugam, Sivnes Raj (Halliburton) | Hashim, Saharul (Halliburton) | Balasandran, Anandhadhasan (Halliburton)
Abstract Gravel packing in a multilayer reservoir during an infill development project requires treating each zone individually, one after the other, based on reservoir characterization. This paper discusses the installation of an enhanced 7-in. multizone system to achieve both technical and operational efficiency, and the lessons learned that enabled placement of an optimized high-rate water pack (HRWP) in the two lower zones and an extension pack in the uppermost zone. This new approach helps make multizone cased-hole gravel-pack (CHGP) completions a more technically viable and cost-effective solution. Conventional CHGPs are limited to either stack-pack completions, which can incur high cost because of the considerable rig time required for multizone operations, or alternate-path single-trip multizone completions that treat all the target zones simultaneously, with one pumping operation. However, this method does not allow for individual treatment to suit reservoir characterization. The enhanced 7-in. multizone system can significantly reduce well completion costs and pinpoint the gravel placement technique for each zone, without pump-rate limitations caused by excessive friction in the long interval system, and without any fiuid-loss issues after installation because of the modular sliding side-door (SSD) screen design feature. A sump packer run on wireline acts as a bottom isolation packer and as a depth reference for subsequent tubing-conveyed perforating (TCP) and wellbore cleanup (WBCU) operations. All three zones were covered by 12-gauge wire-wrapped modular screens furnished with blank pipe, packer extension, and straddled by two multizone isolation packers between the zones, with a retrievable sealbore gravel-pack packer at the top. The entire assembly was run in a single trip, therefore rig time optimization was achieved. The two lower zones were treated with HRWPs, while the top zone was treated with an extension pack. During circulation testing on the lowermost zone, high pumping pressure was recorded, and after thorough observation of both pumping parameters and tool configuration, it was determined that the reduced inner diameter (ID) in the shifter might have been a causal factor, thereby restricting the flow area. This was later addressed with the implementation of a perforated pup joint placed above the MKP shifting tool. The well was completed within the planned budget and time and successfully put on sand-free production, exceeding the field development planning (FDP) target. The enhanced 7-in. multizone system enabled the project team to beat the previous worldwide track record, which was an HRWP treatment only. As a result of proper fluid selection and rigorous laboratory testing, linear gel was used to transport 3 ppa of slurry at 10 bbl/min, resulting in a world-first extension pack with a 317-lbm/ft packing factor.
Abstract Lost circulation is the most common drilling issue for infill drilling projects in Satun-Funan Fields, South Pattani Basin, Gulf of Thailand (GOT). The depleted sand is possible to be a root cause in many wells based on observation from resistivity time-lapse separation in depleted sands or shale nearby. Therefore, the objective of this study is to estimate fracture pressure related to the depleted sand and design an appropriate Equivalent Circulating Density (ECD) threshold for each well to avoid or minimize lost circulation and well control complication during drilling a new well. This study model is using Eaton (1969) equation. There are 3 input parameters which are Poisson's Ratio and pre-drilled estimated depletion pressure and depth. With limitations of no actual fracturing data and limited sonic log, the maximum ECD while lost circulation reading from Pressure While Drilling (PWD) tool and formation pressure test data were used to back-calculate for Poisson's Ratio and identified a relationship with depth. From the total of 68 wells in the Satun and Funan areas, the interpreted Poisson's Ratio ranges from 0.36 to 0.44 and its linear trend is apparently increasing with depth. To minimize the variation of back calculated Poisson's Ratio the local data become an important key for model validation and maintain the similarity of subsurface factors. This interpreted Poisson's ratio trend will be used to calculate for fracture pressure by incorporating with estimated depletion pressure and depth that expect to encounter in each planned well. The lowest fracture pressure in a planned well is used to prepare pre-drilled ECD management plan and a real-time well monitoring plan. Additionally, the model can be adjusted during the operational phase based on the new drilled well result. This alternative model was applied in 4 trial drilling projects in 2019 and fully implement in 6 drilling projects in 2020. The lost circulation can be prevented with value creation from expected gain reserves section is $57M and cost avoidance from non-productive time due to lost circulation is $3.4M. With an effort, good communication and great collaboration among cross-functional teams, the model success rate increases by 12%. However, there are some unexpected lost events occurred even though the maximum ECD lower than expected fracture pressure. This suspect as a combination of limitations and uncertainties on key input parameters and drilling parameters. In the future, the model is planned to expand to other gas fields in the Pattani Basin which will move to more infill phase and have higher chance of getting lost circulation to maximize benefits as the success case in Satun and Funan fields.
Dzulkifli, Izyan Nadirah (PETRONAS Carigali Sdn. Bhd.) | M. Yusoff, Amy Mawarni (PETRONAS Carigali Sdn. Bhd.) | Basri, Abdul Hakim (PETRONAS Carigali Sdn. Bhd.) | Jamaludin, Izzuddin (PETRONAS Carigali Sdn. Bhd.) | M. Som, M. Rapi (PETRONAS Carigali Sdn. Bhd.) | M. Akram, M. Faizal (PETRONAS Carigali Sdn. Bhd.) | M. Diah, M. Amri (PETRONAS Carigali Sdn. Bhd.)
Abstract Major reservoirs in Field A namely A-2, A-3U, A-3M, and A-3L, are deposited within a multi stacked channel complex system within Group I in Malay Basin. These reservoirs were previously understood based on existing data to have no or very minimal vertical communication between them and are treated as separate systems. In 2018, three wells were proposed to drain the attic oil in the north region of A-3U reservoir. When drilling these infill wells, it was discovered that the pressure has exceeded initial reservoir pressure although the reservoir has been idle for almost a year prior to the drilling. The results of the multi-rate test of two of the three infill wells that are less than 1 km apart are significantly different from one another. Post drilling, more tests were executed to investigate the connection between the sand. Studies were also done by incorporating the static and dynamic reservoir modeling data. Based on the result of the tests and studies, it was concluded that all of the major sands are connected at some areas. This new finding on the connectivity might be able to explain the additional volume needed to history match some of the reservoirs. Establishing stratigraphy concepts of a reservoir particularly in a channel complex system is an ongoing process, in this case, a brown field of almost 20 years of production. All data including new well data and dynamic data plays a vital role for a better understanding of the reservoir. It is essential to incorporate the updated geological understanding into the static model to have a representative simulation for better history matching and prediction. Moving forward, instead of building a separate grid model for each reservoir, a larger framework consist of intercalated reservoir grids will be built with this new geological understanding for dynamic simulation.
Abstract Depleted Fracture Gradients have been a challenge for the oil and gas industry during drilling and cementing operations for over 30 years. Yet, year after year, problems related to lost circulation, borehole instability (low mud weight due a low fracture gradient), and losses during cementing operations leading to NPT and remedial work continue to rank as some of the top NPT events that companies face. This paper will demonstrate how the geomechanical modeling, well execution and remedial strengthening operations should be implemented to provide for a successful outcome. The use of a Fracture Gradient (FG) framework will be discussed, and the use of a negotiated fracture gradient will highlight how the fracture gradient can be changed during operations. This paper will also show actual examples from Deepwater operations that have successfully executed a detailed borehole strengthening program. Through our offset studies and operational experience, we will provide a format for navigating complex depleted drilling issues and show an example on recovering from low fracture gradients. This paper will demonstrate (1) how our framework facilitated multi-disciplinary collaborative discussion among our subsurface and well engineering communities; (2) how the impacts of drilling fluids and operational procedures can change this lost circulation threshold; and (3) how our negotiated FG approach has successfully delivered wells drilled in narrow margins.
Abstract The performance of pre-stack depth migration (PSDM) on the fiber optic, distributed acoustic sensing (DAS), vertical seismic profile (VSP) data has rarely been reported. We show the results of PSDM for the fiber optic cables, newly developed and tested at a field in Canada. We apply Kirchhoff migration, Fresnel volume migration and reverse time migration (RTM) to the walkway VSP data to obtain high resolution images of the shallow to deeper structures and provide the performance analysis of the migration methods for the DAS VSP data.