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.
Low Resistivity low contrast (LRLC) reservoirs were normally disregarded due to high water saturation and classified as tight sand. LRLC reservoir defined as Pay that has low resistivity contrast between sand and adjacent shale due to presence of conductive mineral or fresh water. Hence, this paper will transform the standpoint by demonstrating values and potential reserve addition underneath LRLC reservoir which proves that it could contribute equally as the conventional reservoir and realizing potential reserve growth.
HY field located in Baram Delta Basin East Malaysia has been producing for more than 40 years and classified as lower coastal plain to coastal environment. The reservoir is loosely consolidated, fine to very fine sandstone and interbedded with shale. Z reservoir (Low Resistivity contrast reservoir) initially identified as gas-bearing reservoir with fresh water salinity of 2k-4kppm. Plus, difference in resistivity values between sand and adjacent shale only separated by ~3ohmm .Due to these claims, there is no Oil interpreted below the gas level and been neglected for years.
A robust water salinity investigation supported with the geological point of view and water sample taken at the wellhead, Project Team proposed the water salinity should be 10k-15k ppm which is more saline than previously assumed. Revision in water salinity value has led to pinpoint Z reservoir as Oil bearing reservoir and recover estimated ~200 ft Pay of Oil column in Z reservoir.
An appraisal well was drilled for data gathering and exploring potential in the deeper sections, hence serve as a platform for further petrophysical evaluation in the Z reservoir. As a result, Project team managed to take Oil sample and Oil gradient for Z reservoir. In addition, PVT lab result showed the oil sample taken having similar fluid property as the produced oil in the major reservoir. Based from the existing static model, potential additional of recoverable reserves was calculated around 20 MMstb for the Z reservoir. This has been an eye opener for the team to give an extra attention and emphasis on the true potential beneath the LRLC reservoir.
Suboyin, Abhijith (Khalifa University of Science and Technology) | Rahman, Md Motiur (Khalifa University of Science and Technology) | Haroun, Mohamed (Khalifa University of Science and Technology) | Shaik, Abdul Ravoof (Khalifa University of Science and Technology)
Augmented by the recent activities in unconventional reservoirs, it can be easily said that hydraulic fracturing has become a pivotal component for the successful development of unconventional reservoirs. This novel study deals with the investigation of fracture propagation behavior in shale gas reservoirs under varying controllable and non-controllable parameters. In addition to the analysis of propagation behavior, their interaction in the presence of natural fractures are reviewed and quantified.
It is highly challenging to quantify and address the distinct contributions of an element due to the level of heterogeneity that is present in reservoirs. In-situ stress has been reported to be such a dominant contributor to the fracture propagation behavior as they are imperative to assess the extent and the direction of fractures. An enhanced dynamic simulation was conducted to investigate fracture propagation behavior in shale gas reservoirs under varying parameters which were categorized as controllable and non-controllable with respect to the fracture design, treatment and drilling process. After an extensive assessment, a set of natural fractures were introduced to the system and the system behavior was further analysed.
The constructed model is verified with traditional and published models to validate the generated results. It is illustrated that even modest variations of the associated principal stresses between the target zones and the bounding zones can severely limit hydraulic fractures. Further simulation runs under varying fluid conditions and its associated properties revealed similar observations. With the introduction of natural fractures, it is demonstrated that the distribution of the natural fracture network plays a critical role in the cumulative gas production along with its description. Additional investigation illustrates and verifies that fracture width assists in better performance as compared to fracture length for the defined conditions. Fracture placement along with its orientation and proppant properties are also considered to further examine the associated response on productivity.
This novel investigative approach will create a paradigm for future studies that will assist in a simplified prediction of fracture propagation behavior, its associated drilling parameters and anticipated response. In addition, an extensive investigation for the quantification of changes with respect to the variation in prime contributors is presented, which assists in the validation of modern best practices approach.
Khair, Abul (PETRONAS Research Sdn Bhd) | Zakaria, H. (PETRONAS Research Sdn Bhd) | Ali, A. (PETRONAS Research Sdn Bhd) | R., Y. Som (PETRONAS Research Sdn Bhd) | Hady, H. (PETRONAS Research Sdn Bhd) | Baharuddin, S. (PETRONAS Research Sdn Bhd) | Goodman, A. (PETRONAS Research Sdn Bhd)
Big attention was directed towards the deepwater fields offshore Sabah area after the discovery of commercial hydrocarbons Sabah in 2002. Hundreds of wells were drilled in up-faulted structural traps within North East trending thrust ridges which some of it are dry. The interpretation of these reservoirs was established as a series of four turbidite fans from Upper Miocene to Pleistocene. Yet, no correlation was found between the same fan in different locations with regards to geometry, thickness and mineral composition. This research studied over 50,000 sqkm of 3D seismic surveys, over 100 wells with different sets of logs including image logs, cores from two wells and bathymetric images. Normal seismic structural interpretation was conducted and seismic attribute of the turbidite fans were analysed. Seabed morphology was examined using bathymetry surveys and 3D seismic. The deepwater sediments type and depositional environment were investigated using core and log data.
The geometry of the oil prone sand reservoir bodies and heterolithic sand bodies within the deepwater fields was found to be of three types: North East trending narrow sand channels and turbiditic channel levees in the Southwest area of deepwater offshore Sabah, North East trending confined turbidite sand bodies bounded by elevated structural ridges south and south east of type 1, Deepwater fan system composed of channel sand, levee turbidites and local and regional MTD to the North East of type 1
North East trending narrow sand channels and turbiditic channel levees in the Southwest area of deepwater offshore Sabah,
North East trending confined turbidite sand bodies bounded by elevated structural ridges south and south east of type 1,
Deepwater fan system composed of channel sand, levee turbidites and local and regional MTD to the North East of type 1
This new understanding of the source and sediment supply of the deepwater fields Northwest (NW) Sabah explains the geometry, distribution and lack of correlation within the Miocene sediments. Thus, this study will direct the future exploration in the deepwater reservoirs.
Optimum mud window prediction is very crucial for drilling any well. Accurate prediction of pore pressure, fracture pressure and other geomechanical parameters such as stresses, rock mechanical properties and finally the collapse pressure are key for designing the optimum mud window and effective well planning. Predrill predictions of pore pressure and wellbore stability become more and more challenging as the industry is moving to more and deeper and ultra-deep water wells. This is primarily becaue of lack of offset calibration together with inherent probrems and challenges associated with deep water environments. A substantial amount of nonproductive time (NPT) was associated during the initial phases of drilling campaigns in the Brunei deepwater. Accurate mud weight window prediction using regional scale pore pressure prediction and geomechanical modeling clearly demonstrated a significant reduction in nonproductive times over the different phases of drilling campaigns till date. This also includes a regular update or refinement of the model as soon as new data or information becomes available. This paper presents some of the methodologies employed during well planning and construction with refinement along the way, resulting in improvement on pore pressure and geomechanical model. Our intent is to document and share our experiences and lessons learnt in Brunei deepwater well so that design and execution workflow can be continuously improved thus the well can be delivered safely and costeffectively.
Zulkipli, Siti Najmi Farhan (PETRONAS Carigali Sdn. Bhd.) | Mehmet Altunbay, Michael (PETRONAS Carigali Sdn. Bhd.) | Gaafar, Gamal Ragab (PETRONAS Carigali Sdn. Bhd.) | Shah, Jamari M. (PETRONAS Carigali Sdn. Bhd.)
Objectives of obtaining in-situ values of water saturation, formation water salinity, true formation resistivity (Rt) and SCAL data by core analysis can only be achieved if extraneous fluid invasion is kept at a controlled level and corrected for it or be prevented. The impossibility of zero invasion of cores by mud-filtrate makes the traced-coring a compelling method. Application of liquid based tracers such as tritium and deuterium oxide (D20) to determine the amount of fluid invasion is highly recommended in the event of critical in-situ formation properties need to be determined from core. This study presents a set of key factors for controlling invasion of core by extraneous fluids, best practices in quantifying the fluid invasion, handling core at the surface, and suggests types of analyses, specifically, for unconsolidated formations. A comparison of petrophysical parameters determined from traced-core against the results of LWD log interpretation of the same interval is also presented to assess the success/failure of the recommended practices.
The main use of core-driven parameters has dual functionalities. They are used for calibrating LWD data and also are used to form a statistical database for static modeling. Calibration of LWD data with properly obtained core parameters could minimize uncertainties in calculated petrophysical parameters and establish a ground-truth in petrophysical work especially in water saturation (Sw) calculations. In our case study, good agreements are observed between log derived and core measured water saturations and salinity values extracted from the core against salinity from petrophysical study.
Proper time management, core preservation technique, prompt logistical arrangements and well-site core plugging are seen as the main driving factors for a successful coring job. Comparison of fluid invasion profiles between core plugs drilled at well-site and plugs drilled later in the lab are presented to demonstrate and emphasize the importance of time-factor which constitutes the main challenge in the case study and in general. The lack of data from uncontaminated core may result in significant financial losses that may manifest itself as bypassed productive zones, erroneously determined as wet or no-production (dry) intervals, wrong completions or incorrect quantification of actual and recoverable hydrocarbons. Some of these problems are associated with lack or mismanagement of uncertainties in calculation procedures/algorithms; therefore, can be alleviated or lessened with representative and accurate core data. In addition, analyses results based on the representative core could promote better understanding of reservoir behavior and catalyze more refined reservoir management strategy.
The experience acquired in this study revealed and ranked the importance of timing of the events and the procedural steps to obtain minimally invaded core plugs in a traced-core operation. Time is the most critical factor to prevent post-drill fluid-invasion and fluid re-distribution within a core which adversely impact core analysis results. Therefore, the optimum time allowed between the coring and laboratory tests, core transportation strategy, corresponding contamination of core as a function of time, recommended tests, selection of tracers and quick calculation of required tracer volume are the outputs that are elaborated in this paper. This study also highlights potential challenges in coring unconsolidated formations and serves a mitigation plan for lessening invasion of core by providing a set of recommendations for best practices.
Gelinsky, Stephan (Shell International E&P) | Kho, Sze-Fong (Shell International E&P) | Espejo, Irene (Shell International E&P) | Keym, Matthias (Shell Malaysia) | Näth, Jochen (BSP) | Lehner, Beni (BSP) | Setiana, Agus (BSP) | Esquito, Bench (SDB) | Jäger, Günther (SDB)
Prospects below or near shallower producing fields can be economically attractive yet also risky since reservoir presence may be uncertain, reservoir quality can be poor, and high overpressure and temperature can make drilling and logging deeper prospects difficult. Systematic integration of relevant subsurface data from thin section to basin scale allows to seismically identify reservoir presence, and to predict reservoir quality for applicable rock types via burial histories. On an intermediate well log to seismic scale, a predictive rock physics modeling approach links reservoir and seal rock properties to seismic amplitude data to polarize the prospect's geologic ‘probability of success'. Particular challenges in the offshore Brunei study were very fine-grained deposits and non-vertical tectonic stresses associated with compressional settings. Both make porosity predictions that leverage complex burial histories rather than relying on extrapolated depth trends quite challenging - yet the integrated approach remains the best option to identify deep reservoir quality sweetspots that a favorable stress and temperature history may have preserved for certain reservoir rock types in certain locations.
The prolific petroleum system offshore Brunei features two major sediment fairways, the Baram and Champion river systems, and a variety of depositional environments, ranging from high NtG topsets inboard over shallow marine slope settings to deepwater turbidites outboard (
Omar, M Mizuar (PETRONAS Carigali Brunei Ltd) | Rasli, M Faiz (PETRONAS Carigali Brunei Ltd) | Paimin, M Razali (CANAM Brunei Oil Ltd) | Maulana, Herry (CANAM Brunei Oil Ltd) | Ghosh, Amitava (Baker Hughes) | Abidin, M Zyden Su'if B Zainal (Brunei National Petroleum Company)
Pore pressure prediction and geomechanical modelling play a very important role in well planning and is one of the many challenges facing the oil industry today, as exploration focus worldwide is moving more and more into the deep-water environment. Pressure related problems in deepwater wells are mainly associated with narrow operating window resulting in severe well control incidents, sometimes even leading to early abandonment. A better understanding of the prevalent pore pressure regimes in terms of generating mechanisms along with pressure maintenance and dissipation through geologic time offers invaluable insight and perception about these challenges and also on our ability to predict and mitigate or minimize them. Borehole instability related problems like excessive wellbore breakout can result hole cleaning issues, stuck pipe, setting casing earlier or potentially losing the wellbore. It is important to analyze these challenges and develop an understanding of the same, prior to drilling so that, various plans and mitigation systems can be put in place.
A substantial amount of non-productive time (NPT) was associated during the initial phases of drilling campaigns in the Brunei deepwater. Accurate mud weight window prediction using regional scale pore pressure prediction and geomechanical modeling clearly demonstrated a significant reduction in nonproductive times over the different phases of drilling campaigns till date. This also includes a regular update or refinement of the model as soon as new data or information becomes available.
This paper presents some of the methodologies used during well planning and construction of deepwater and ultra-deepwater wells. It also discusses the work refinement throughout each drilling campaigns, which resulted in improvement on geological and geomechanical model. It is imperative to note that the intent is to document and share experiences and lessons learned in Brunei deepwater wells within the industry. This would enable the execution workflow and well design to be continuously improved for a safe and cost-efficient delivery of the wells.
Abija, Abija (Akaha Celestine/Dept. of Geology, University of Port Harcourt) | Ankwo, Fidelis (Akaha Celestine/Dept. of Geology, University of Port Harcourt) | Tse, Tse (Akaha Celestine/Dept. of Geology, University of Port Harcourt)
In situ stress magnitude and orientation are necessary for oil and gas field development planning to achieve optimal well placement whether vertical, deviated or horizontal, wellbore stability analysis for safe and stable drilling to reduce non-productive time, fault stability and cap rock integrity modeling for CO2 geosequestration and stage placement of hydraulic fracture for optimum production in unconventional plays. These were evaluated using wireline logs, leak off test and vertical seismic profile data in an onshore field, Eastern Niger Delta whose stratigraphic sequence is the typical interlayered, normal to abnormal pressured shales and sandstones of the Agbada Formation. The vertical stress magnitude ranges from 23.08 - 25.57 MPa/km, minimum effective horizontal stress from 13.80 - 14.03 MPa/km and maximum effective horizontal stress from 16.06 - 17.65 MPa/km inferring a normal fault stress regime. The minimum horizontal stress orientation varies from 16° - 33° forming the most stable orientation for geosteering a directional well while the maximum horizontal stress orientation is N60°E - N123°E in agreement with the regional fault orientations in the Niger Delta. ENE – WSW, WNW – ESE and other maximum horizontal stress orientations suggest multiple sources of stress, and in situ stress rotation across fault surfaces depicts wellbore instability issues. Structural evolution depicts NE – SW and NW-SE trending faults in the direction of the maximum horizontal stress. Directional well inclination angles of 16° and 33° were predicted in wells 10 and 11 respectively and mud weight window predicted using 2D Mohr - Coulomb failure criterion yielded an optimum mud weight window of 10 - 14.0ppg with overpressure accounting for mud weights as high as 25ppg and minimum mud weight exceeding the maximum mud weight in some sections.
Gomez, Max (Pacific Rubiales Energy) | Florez Anaya, Alberto (Pacific Rubiales Energy) | Araujo, Ysidro Enrique (Pacific Rubiales Energy) | Parra Moreno, Wilson (Pacific Rubiales Energy) | Bolanos, Viviana (Pacific Rubiales Energy) | Landaeta, Libia (Pacific Rubiales Energy)
Rubiales and Quifa are the Colombia’s major heavy oilfields (oil gravity ranges from 11.3 to 14.4 °API) with a current oil production of more than 260 MSTB with an oil viscosity ranges from 370 to 730 centipoises. Horizontal well technology is used to drill through unconsolidated sandstones with an active and strong aquifer, under primary depletion. Since 2006, 604 horizontal producer wells have been drilled and completed using slotted liner in open hole.
The high water production rate from the beginning of the operation in the horizontal wells is the main problem to be controlled in the Rubiales and Quifa fields, due to the high cost of produced water treatment and other factors. Water production is inevitably associated with the oil production; however one of the biggest challenges is to delay the water production as much longer as possible.
Rubiales and Quifa actually have a large number of closed wells that have reached its economic limits, mainly by high water production. This production imbalance is being addressed in the new horizontal wells, using inflow control devices (ICDs). The ICDs is placed in each screen joint to balance the production influx profile across the entire lateral length and compensate the permeability variation and therefore the productivity of each zone.
In 2012, a pilot test has been designed and implemented in Rubiales field with three horizontal wells using passive ICDs completion. The performance of the ICD’s is found to reach the highest cumulative oil production compared to neighboring wells. The main purpose of this paper is to detail the selection process design and results evaluation for the use of the passive ICDs in horizontal wells at Rubiales and Quifa Fields, heavy oil reservoirs.