Shale plays are anisotropic in terms of their reservoir quality which gets reflected in their productivity. Reservoir qualities like organic richness, thermal maturity, hydrocarbon saturation, the volume of clay, brittleness and pressure affect the productivity of the shale plays. In general, the volume of clay has a negative relationship whereas other parameters listed above have a positive relationship with production. In our study area, we found the deepest wells despite having better rock quality; do not perform like nearby shallower wells. The objective of this study is to understand the not so obvious reason behind underperformance of these deepest wells.
Since the wells are located at a deeper depth and the reservoir temperature is high (90 to 135°C), so we studied the area from clay diagenesis and fluid expansion perspective. We have reviewed the imprints of clay diagenesis with the help of XRD data and core integrated multi min processed wireline logs. We observed an increasing trend of illite, chlorite towards the deeper part of the reservoir along with a decreasing trend of smectite in the same direction which indicates a higher degree of clay diagenesis. Fluid expansion study is carried out with the help of total organic carbon and hydrocarbon saturation. This study indicated a higher degree of fluid expansion (TOC to hydrocarbon generation) in the deepest part.
Subsequently, 1D pore pressure, stress and rock mechanical modeling is carried out to evaluate the effect of a higher degree of diagenesis and fluid expansion on geomechanical parameters (pore pressure, stress and brittleness). 1D modeling reveals that the deeper wells have abnormal pressure, stress and low brittleness, which is primarily due to extra pressure contribution from fluid expansion and clay diagenesis apart from the compaction disequilibrium process. This abnormal stress and reduction in brittlness likely to have created challenges for the applied hydrofrac job in the deepest part resulting to narrow frac geometry. Comparison of hydraulic fracture modeling between a shallow and the deepest wells reveal that the hydraulic fracture geometry in the deepest well is narrower than the shallower well. So we came to the conclusion that the deepest wells are underperforming than the shallower wells despite of their better rock quality due to ineffective fracturing and comparatively narrower fracture geometry.
The impact of clay diagenesis and fluid expansion in shale productivity has not been studied widely. Though many authors have extensively studied the impact of clay diagenesis on permeability and pore pressure, the integration of shale well production is rarely attempted. This work will help the operators to better analyze and understand their shale reservoir from clay diagenesis and fluid expansion point of view before planning the hydrofrac jobs.
Arisandy, Mellinda (PETRONAS Carigali Indonesia Operations) | Mazied, Miftah (PETRONAS Carigali Indonesia Operations) | Putra, Bayu P (PETRONAS Carigali Indonesia Operations) | Yogapurana, Erik (PETRONAS Carigali Indonesia Operations) | B Mohd Idris, Jamin Jamil (PETRONAS Carigali Indonesia Operations) | Darmawan, Hendra I. (PETRONAS Carigali Kuala Lumpur)
This paper describes geochemistry analysis, hydrocarbon charge and entrapment model for prolific "MA" Block in the West Natuna Basin. Even though the area is currently at a mature exploration stage, the behaviour of hydrocarbon distribution in the area is still poorly understood and the link between discovered hydrocarbon and possible kitchens is still unknown. This study is an attempt to understand hydrocarbon expulsion, charging and entrapment in "MA" Block to de-risk further exploration efforts.
Several localized inverted half-grabens were identified through seismic interpretation. Nearby wells were then selected in evaluating source rock quality and maturity. In order to determine hydrocarbon expulsion model, 1D-3D burial history and thermal maturity models were constructed using integration of source rock and fluids geochemistry, temperature, seismic, and well data. Hydrocarbon charge and entrapment models were then simulated using 3D basin modeling software and calibrated with existing proven accumulation to produce a risked understanding of hydrocarbon distribution in the study area.
This study suggests that the most possible source rocks are the Late Eocene and Oligocene shales of Lama Formation and Lower Gabus Formations. Both source rocks are indicated by type I & type III kerogen. Lama source rock was confined in the initial grabens and post mature in deep paleo-grabens. This study confirmed that charging is derived from four (4) kitchen areas: Anoa, Gajah, Kakap, and Kambing grabens. The oil samples from "MA" Block indicated lacustrine facies. Rock geochemistry analysis portrayed oil-prone and gas-prone source rock.
In general, hydrocarbon was migrated from the southeastern area (Kambing graben) and southwestern area (Gajah graben). Hydrocarbon was later on accumulated in the nearest structural entrapments (anticlines). In the deep grabens (Kakap and Kambing), the hydrocarbon expulsion was starting as early as 37 Ma and 31 Ma, respectively, while in shallow graben (Anoa) the expulsion was starting at 29 Ma. The earliest structural trap commenced at 21 Ma, aligned with the initial compressional regime that was affecting the West Natuna Basin. Notable accumulative erosion in Miocene was nearly 1000 m at inverted structures, by which partly removed regional seal and reduced reservoir effectiveness. Significant yet-to-find hydrocarbon is predicted to be concentrated in the Anoa, Kakap, and Northeast Kambing area.
Radzuan, Nurul Asyikin M. (PETRONAS) | Salleh, Nurfarah Izwana (PETRONAS) | Chandrakant, Ashvin Avalani (PETRONAS) | Rusman, Liyana (PETRONAS) | Zamanuri, Kautsar (PETRONAS) | Bakar, Azfar Israa Abu (PETRONAS) | Yip, Pui Mun (PETRONAS) | Jamaluddin, M. Helmi (PETRONAS) | Ghonim, Elsayed Ouda (PETRONAS) | Nambiar, Vijay (Novomet) | Alexander, Euan (Artificial Lift Solutions)
Following the first pilot success of the truly rigless 3-1/2" tubing cable deployed ESP (TTESP-CD in offshore field of Sarawak Basin, PETRONAS has taken steps to further advance in the technology development and application through more replications within Sarawak and Malay Basin. PETRONAS had been looking into a strong business case for the TTESP-CD technology for a wider application throughout Malaysia region by looking at fields with strong/moderate water drive and low bubble point pressure besides having other limitations on the platform including the facilities reliability issues. TTESP-CD are to be applied widely in Malaysia with more flexibilities in design and improvement towards the subsurface equipment, installation equipment and procedures. With the challenges in the existing completion and production requirement for replications, based on the lesson learnt from the pilot implementation, multiple improvements to the system have been done including; 1) A High Rate Slim Pump with Flexible Application 2) Alignment Tool for Cable Hanger Orientation. With this in place, more opportunities identified for the candidate selection which improve the installation philosophy specifically in dual string applications and enhance the efficiency in installation procedures. Case studies of TTESP-CD replications in Malay & Sarawak Basin for Field T, Field B and Field P presenting the best case for TTESP-CD application with improvement to design, equipment and application. These will bring additional value to PETRONAS with estimated production gain of 1.5 KBD and up to 1.2 MMSTB reserves to be monetized with additional value saving of up to RM 6 Mill. Besides the subsurface challenges, aging offshore assets brings a lot of challenges, especially on the space availability, structural integrity, power availability and distribution, instrumentation and data transmission. This requires an integrated approach from multiple disciplines in delivering the studies as per required within the targeted timeframe.
Mohd Ali, Siti Syareena (PETRONAS Research Sdn Bhd) | Teng, Kevin Ging Ern (PETRONAS Research Sdn Bhd) | A Jalil, M Azran (PETRONAS Research Sdn Bhd) | Sedaralit, M Faizal (PETRONAS Research Sdn Bhd) | Trianto, Adi (PETRONAS Research Sdn Bhd) | Wan Sagar, Siti Fatimah Sarah (PETRONAS Research Sdn Bhd)
The scope of the geomechanical study is to investigate the risk associated with different reservoir depletion strategies and to numerically simulate the geomechanical response of the reservoir rocks. The study focused on the large karstic distribution of the reservoir for the prediction of the best drilling direction and optimum well trajectories, and also to model the pore collapse behavior observed in the high porosity carbonate which will result in surface subsidence and impact the platform facilities placement.
A methodological risk evaluation approach based on numerical simulations with stringent experimental programme has been applied to the field study. The regional geological understanding and operational experience of the nearby fields have been considered for the study via extensive assessment of constitutive models relating to pore collapse. Advanced 4D geomechanical simulations were carried out to incorporate the seismic-based karstic models and to strengthen understanding of the pore collapse phenomena during reservoir depletion. The obtained prediction results were compared to nearby fields and subsequently use for wells, facilities planning and engineering considerations.
The results obtained in the study identified a few key outcomes which are being considered for detailed surface engineering design and well planning. The results have impacted the decision to place the location of the platform away from the center of the seabed subsidence bowl. The predicted reservoir compaction and subsidence described the rate and the magnitude of the subsidence which are use to design the height of the platform to mitigate potential damage induced by wave deck shearing. In addition, the distribution of karst has been mapped through seismic imaging and incorporated in the geomechanical modelling. The results are also used to determine the hazard of the weak zones in each formation and high stress anisotropy regions which are to be avoided for future well placement and to be used for well trajectory optimization. Key findings of the geomechanical-related risk have been identified and considered in the field development plan. Consequently, a Risk Ranking Criteria incorporating the results of advanced simulations and rock testing programme have been developed based on comprehensive weightage and the technical categories.
The paper offers a detailed insight on the geomechanical risk evaluation obtained using 4D finite element coupled reservoir geomechanical simulations. The study addressed the challenging development of a highly karstified limestone reservoir by offering valuable inputs for the well design and facility engineering through prediction of reservoir compaction and seabed subsidence, best drilling direction and optimum well trajectories. This will avoid potential geomechanical related hazards and ensure adequate operational safety levels.
In today's fast paced and challenging oil industry, the need of faster evaluation studies for quick generation of field development plan (FDP) is becoming more crucial to remain competitive. Field's geological and structural complexity, uncertainty of production data adds to the challenges. Traditional approach of building dynamic mesh models carrying out numerical simulation to history match, then predict has always remained time consuming in large mature fields.
The ‘B’ field in Peninsular Malaysia is a mature clastic with stacked reservoirs having a huge gas cap with moderate aquifer. Significant production over last 30+ years led to uneven movement of the gas cap and also of the edge aquifer leading to possibility of bypassed oil. The updated dynamic model could not match the preferential gas cap movement, thus failed to match the high GOR of downdip wells and also unable to match high watercut of certain updip wells. To identify the areas of bypassed oil thus is a significant challenge with the current dynamic model. New engineering tools of polygon balancing, material balance, normalized EUR bubbles were used with the 3D static model volume and the facies understanding. The uncertainties and risks were also identified and clear measurable methods were proposed to address the uncertainties and reduce the risks. Very detailed decision tree with clear data gathering plan to drill successive optimum wells have been planned during the campaign.
This paper details the new engineering tools used to delineate and quantify the bypassed oil in these huge clastic reservoir with preferential gas and water movement, unable to be history matched by the dynamic model. It explains the engineering methods applied to identify and quantify the 10 infill wells proposed for the development campaign. To reduce risks, this paper would also explain the blind testing that was carried out on for this new reservoir engineering analysis tool by deriving the infill potentials of the previous campaign (4 years back) by the same method.
The paper details how robust technical development plans were generated having infill well locations and reserve determination. This paper will also demonstrate the classic "Do-Learn-Adapt" strategy through its infill wells prioritization & ranking, subsurface de-risking analysis, data acquisition and mitigations plans.
Brownfield in Balingian and Baram Delta have handful of idle wells and well to be abandoned in their inventories. The project aims to reduce the idle well inventories and support production gain through monetizing behind casing opportunities. The target is to appraise and develop LRLC potentials with lower cost of appraisals. This will maximize full field potentials before abandonment and leads to future development of LRLC opportunities as conventional reservoir becomes more difficult to develop.
The idle well inventory has grew up due to problem in production (increase water cut, HGOR) and well problems (sand, fish). An order has been introduced to reduce the idle well list up to 50%. Additionally, in the past, the LRLC intervals were often ignored and considered as water-wet sands due to high water saturation or as tight sands. These intervals, that contain significant reserves, are recognized in many technical papers explaining its identification and evaluation techniques from well-data (logs and samples/cores). The scope of the project is to rejuvenate the idle wells by add-perf LRLC reservoirs.
It is impossible to achieve the target without the presence of proper and improved LRLC BCO evaluation process, thus an integrated workflow approach (between Petrophysicist, Reservoir Engineer, Production Technologist, Asset manager & Well Intervention group) has been developed and applied in the project. A new evaluation tools had also been developed called REM (Resolution Enhanced Modelling) in order to improve the log properties of LRLC reservoirs so that the data obtained from old conventional tools can still be used to evaluate LRLC reservoir. Although LRLC is termed UNSEEN, the risk is reduced by proper understanding of hydrocarbon column and sand development.
To date, 7 fields are already benefitted from this approach. Field A LRLC reservoir for example has tripled the hydrocarbon saturation, and net to gross has improved to 20% using REM compare to 5% without REM. The other 6 fields are also gaining the same increase in the properties. This has resulted in a cumulative potential of 4.4 MMstb of reserves addition and ~11 KBopd potential gain. As a result, a better and attractive BCO proposals can be generated from LRLC opportunities. The exercise will provide the company with cheaper options of appraising and developing LRLC reservoir while reducing the idle wells. There is no better way of understanding LRLC reservoir; as no tools can identify & quantify it yet, rather from the actual production.
Ismail, Hasnol Hady (PETRONAS Research Sdn Bhd) | Lew, Chean Lin (PETRONAS Research Sdn Bhd) | Mohamad Som, Muhd Rapi (PETRONAS Research Sdn Bhd) | Abdul Kadir, Mohd Fauzi (Energy Quest Sdn Bhd) | Ahmad Tajuddin, Mohamad Raisuddin (Energy Quest Sdn Bhd)
Modelling of meandering fluvial reservoirs with point bars and crevasse splays is very challenging. The conventional modelling approaches, especially for meandering fluvial reservoirs, are mainly controlled by wells, which have contributed to uncertainties in lateral variations between and away from well control. Integration of the improved sedimentology, geophysics and 3D reservoir geomodelling techniques of fluvial reservoir system are proposed in the study. In stratigraphic and structural framework building, the improved methodologies included 3D seismic geobody extraction, stratal slicing and high order architectural elements interpretation. 3D geobody extraction and stratal slicing technique enhanced interpreter ability to visualize fluvial features at specific time-equivalent stratigraphic surface. In lithofacies modelling, more refined high-order architectural elements were modelled using methodologies included 3D facies seismic probability, local varying azimuth and dip angle to capture lateral accretion of point bars inside the channels for better facies distributions following point bar architectures. In property modelling, porosity was populated using Gaussian Random Function Simulation constraint to lithofacies trend to control the distribution of porosity away from wells. This methodology resulted in the porosity distributions being well controlled following the lithofacies trend. The proposed workflows and methodologies enable geomodeller to produce a more geological realistic meandering fluvial reservoir model with internal lithofacies and property distribution honouring well data and input distribution.
The existence of elastic anisotropy in the reservoir is obtained through the equivalent media theory. An isotropic elastic theory fairly explains the reservoir modeling or characterization but its not well explain anisotropic characteristic fairly for reservoir characterization which is extremely challenging without considering a self-consistent theory of effective equivalent media theory. In this research, equivalent media theory has been explained and implemented on a producing well-log data with consistent Vp, Vs, density and other parameters. Instead of using Voigt averaging, equivalent media theory used to estimate the effective stiffness parameters and compare with Thomsen's parameters and finally used effective anisotropy parameters and compare with gamma log. Result shows the effectiveness of equivalent media theory for future application for developing reservoir modeling and characterization.
Nik Kamaruddin, Nik M Fadhlan (Petroliam Nasional Berhad) | Teng, Kevin Ging Ern (Petroliam Nasional Berhad) | Musa, Ikhwanul Hafizi (Petroliam Nasional Berhad) | Tan, Chee Phuat (Petroliam Nasional Berhad)
This paper presents a study on the risk associated with CO2 injection in geological storage and fault reactivation through a comprehensive workflow for determining the feasibility of CO2 storage campaign in carbonate reservoir in Malaysia. The study includes constructing a 4-D coupled reservoir geomechanical model and developing a workflow that can be used to evaluate geomechanics risks associated with carbon capture and storage (CCS) by outlining results and findings that drive key decisions in the planning of CCS strategy.
The workflows aims to better delineate and enumerate the risks with CCS as it constructing and calibrating single well models by corroborating numerous inputs including stringent laboratory testing data and drilling analysis, and combining with structural model and reservoir model to create a field wide 4-D geomechanical model using advanced time lapsed geomechanics simulation. Coupled simulations with the dynamic reservoir model provided predictions of the fault stability by considering fault deformation. The paper further highlights the geomechanics evaluation consideration (economics and engineering trade-off) in designing maximum safe injection pressure for CO2 sequestration program.
The results of the study show fault condition subjected to different time-steps of the coupled simulation during depletion and injection. At each time-step, the development of plastic shear strain and absolute displacement are plotted and risks associated with the change in reservoir pressure are assessed and quantified. Different injection plans are modelled to determine the impact on final storage capacity, long term fluid containment and upper safe injection limit to avoid breaching the caprock.
The study offers the utilization of the latest techniques in 4-D coupled geomechanical modelling which reduced the study time and cost significantly, making it affordable for in-time solution for decision making. The paper also aims to encourage the consideration of the applied novel workflow involved in CCS strategye valuation focusing on risk assessment which ultimately will affect reservoir maximum safe injection limit, capacity, long term storage safety, and monitoring program to mitigate potential geohazard leakage.
This paper presents the first successful application of ceramic sand screens offshore Malaysia. Ceramic sand screens were considered as a remedial sand-control method because of their superior durability and resistance compared with metallic sand screens. An early commitment to integrate MPD into an HP/HT drilling operation can make MPD more than just an enabling tool and turn it into a performance tool that offers significant operational benefits. Pore-pressure prediction plays an important role in well planning as exploration targets shift to deeper, overpressured reservoirs. The Samarang oil field, offshore Sabah, Malaysia, is undergoing a redevelopment project with integrated operations.