bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydrocarbon Identification and Evaluation in a Bioturbated Reservoir with New-Generation Pulsed Neutron Technology
Authors: Kantaatmadja Budi P. , Jiang Long , Ralphie Benard , Juan Saw Li , Thien Kim Nguyen
Published: October 2019

High-water-saturation (Sw) bioturbated zones are generally bypassed due to the perception that those are non-oil-bearing, nonproductive zones. The major challenge in bioturbated pay zones is low resistivity, which leads to high Sw calculation. The hydrocarbon could then be bypassed in the existing completion. The high Sw also contributes to an inaccurate static model and stock tank oil originally in place (STOIIP) calculation. This study is to prove that bioturbated zones can add oil flow (as part of behind-casing opportunities from the current idle wells in many fields in Malaysia) and contribute meaningfully to the STOIIP.

The objective of this paper is to use multifunction pulsed neutron service to identify and quantify the remaining oil saturation in bioturbated reservoirs. The examples shown are from a mature field located in offshore Sarawak.

Pulsed neutron logging (PNL) is a well-established technology in casedhole reservoir monitoring and evaluation. However, the challenging environment with dual-tubing completions makes quantitative interpretation very difficult. The new generation slim pulsed neutron logging tool used in this study improves both sigma (∑) and carbon/oxygen (C/O) ratio. It also provides fast neutron cross section (FNXS), a new measurement very sensitive to formation gas and dry weight total organic carbon (DWTOC). More reliable answers help the subsurface team to select the perforation intervals confidently.

The hydrocarbon zones in bioturbated reservoirs were clearly identified. The remaining oil saturation was computed from much improved C/O ratios and the independent DWTOC method. The positive production results confirmed that the measurements and interpretation are accurate and more robust.
Experience of Distributed Temperature Survey DTS Strengthen the Understanding on Heterogeneous Carbonate in Southern Iraq Oilfield
Authors: Sidek Sulaiman , Idris Khairul Nizam , Faisal Ahmad Hisyam , Mohd Zaini Khairul Nizam , Sumainah Amr
Published: October 2019

This paper discusses case histories, where Distributed Temperature Survey (DTS) with Fiber Optic Enabled Coiled Tubing (FOECT) was used during stimulation treatment and well testing by the Operator in Southern Iraq oilfield.

The field was discovered in 1984 with hydrocarbon accumulation in four (4) major reservoirs, first oil production was achieved from the top carbonate reservoir in 2013. The wells were drilled to penetrate a thick carbonate reservoir which ranges from 80m to 100m thickness, subsequently completed as single selective producer with cemented casing and perforated across the targeted zone. Permeability and porosity varies drastically within same carbonate reservoir thus effective treatment fluid diversion is required to ensure the largest possible surface area of the reservoir is contacted and exposed to stimulation fluid to achieve uniform stimulation and sustainable production.

Main challenge for stimulation treatment in heterogeneous carbonate reservoirs is to achieve optimum placement of the stimulation fluid without some knowledge of, and control over where the treatment fluids flow. Traditional way to record production and injection fluid profile is via running a production logs with wireline equipment, however this require additional equipment and time. This was addressed by using CT equipped with fiber-optic real-time telemetry, that offer 3D temperature profiling which significantly improved the stimulation treatment by providing downhole monitoring throughout the entire treatment and thus a new level of control of fluid placement. In addition, the FOECT allow real-time interpretation of Pressure Transient Analysis (PTA) to evaluate the well deliverability, production performance of the stimulation treatment and basic reservoir description (e.g. permeability and total skin).

This technique helped in reducing time and the number of well intervention runs, while improving fluid placement to achieve faster, more informed stimulation treatment. Lessons learned from these case histories enhanced Operator understanding of the reservoir and led to recommendations for future treatments and potential replication.

Steps and considerations in decision making, reaching the most advantageous solution for the stimulation treatment as well as the detailed engineering evaluation for the two (2) wells candidates will be addresses in this paper.
Silhouetted Reservoir Clustering and Connectivity Network Visual Analytic Techniques in Assisted History Matching
Authors: Ghamdi Amell
Published: October 2019

History matching field performance is a complex and time-consuming process yet it is a crucial step towards constructing reliable predictive models. This paper presents a novel approach where visual analytics plays a role in optimizing history matching process when used as an input to Assisted History matching applications (AHM). Silhouetted Clustering (graphical representation) is the technique used to interpret and validate consistency within clusters. This technique is using k-mean algorithm, which is an Unsupervised Algorithm.

The methodology used starts with identifying the optimal number of clusters of reservoir model grid cells using Silhouetted Clustering. This was done by discovering the reservoir geo-bodies and classifying them based on patterns of static rock properties. Once the optimal number of clusters is found, sensitivity are then formulated to run on all generated clusters maintaining a property multiplier value throughout the runs. That is to detect the most effective clusters on matching field historical performance. The last step is performing sensitivity runs on the most effective group of clusters using different ranges of the property multipliers until a satisfactory match is found.

The new methodology shows a significant improvement in the matching quality of the reservoir model as a result of the cohesive clusters. Those unified clusters helped to, easily, pinpoint the candidate cluster for property modifier. This greatly improved the quality of history matching the reservoir without affecting its geo-bodies nature. The main challenge is to decide on the right number of clusters that mimics the natural grouping and distribution of the reservoir properties. The optimal number of clusters is selected based on silhouette average value, clusters' density and well separation. Therefore, Silhouetted Clustering was used to validate the cohesion within the reservoir clusters in minutes.

The novelty in this approach is introducing Silhouetted Clustering, a visual analytics technique, to optimize AHM process where we can ensure graphically how well the grid cells classified within its cluster. Moreover, this technique provides the confidence while working with the clusters knowing that the natural pattern of the reservoir is honored. The integration between Artificial Intelligence and Visual Analytics has greatly contributed to improve the overall quality of simulation models in less time.
Drilling Performance Improvement in Mature Field with Limited Investment Period by Implementing Novel Technology Application
Authors: Pratama Raka Cahya , Hutabarat Teddy , Fitryansyah SM Yudy , Benny Benny , Dova Rudi
Published: October 2019

Horizontal well type was selected to optimize drainage of a mature field which had less than 3 years prior concession end. However, the well construction of horizontal well is relatively more challenging compare to other well type which will lead to higher cost. Offset well execution data showing that the challenges of drilling this well type were wellbore instability, drill bit worn out due to gravel zone, uncertainty on marker prognosis and the potential differential sticking on lateral section (inside the depleted reservoir) especially during running pre-perforated liner as completion equipment. It was realized that drilling performance improvement is required to reduce the cost and accelerate the production.

To overcome the challenges, several technologies were introduced. Drilling fluid optimally designed to support borehole stability and real-time adjustment were performed by analyzing the drill cutting. Ridged shape cutter bit utilized to aid during penetrating the gravel zone. To maximize the penetration rate, point-the-bit Rotary Steerable System was utilized for better weight transfer and improved wellbore geometry compare to conventional mud motor system. To manage uncertainty of marker prognosis, the Bottom Hole Assembly (BHA) was designed to achieve maximum dog leg severity capability by minimizing the number of stabilizers. Near bit gamma ray sensor also installed to aid timely formation marker identification. To mitigate risk of differential sticking, the bridging agent sized to fit with the formation permeability through particle size distribution analysis. Centralizers also installed on pre-perforated liner assembly to minimize contact area which might cause differential sticking.

Though these technologies application has been used on many occasions, they were new to this field development which raised concern over their potential risk, especially with limited investment period. Therefore, a series of execution assurance processes were performed. Cross-functional risk assessment sessions were held to review trade-offs of each new technology potential value with the potential cost incurred by considering the possibility of success and potential changes on other aspect of the well construction that need to be adjusted to accommodate the application and mitigate its potential risk. Then a drill-well-on-paper session held with all personnel that would involve by simulating the drilling execution following the procedure which then improved by creating mitigation steps or provide clarity. Artificial intelligence assisted decision support center was also utilized to monitor execution and aid performance improvement recommendation utilizing geomechanics, hydraulic, torque and drag model as well as the field best practices.

These all result to 17% cycle time improvement with 9% lower cost compare to typical well. The production sweet-spot zone exposure also increased by 20%.
Storage Tank Emergency Preparedness in a Modern Era: Incorporating Technology Advancement on a Mature Facility
Authors: Kristanto Kristanto , Witono Johanes-Anton , Victor Irwan , Garmana Iqbal-Aprian , Wongso Henkie-Hartono , Situmorang Ade , Hariyanto Geoffrey , Kusmawan Herdy , Pebtiadi Teguh , Nurdin Farid , Rosyadin Gunawan
Published: October 2019

Mature facilities were previously built based on outdated code and standards which do not yet incorporate lessons from recent incidents. In order to have more robust plant safety management, plant design and Emergency Preparedness are upgraded incorporating new technologies.

The selected upgrading methodology involves comparing the available emergency scenarios versus all possible emergency scenarios that might happen to the facility. Scenarios that already have appropriate mitigations are reviewed in order to adapt with the latest plan condition. Meanwhile, scenarios that were yet considered in the initial design are carefully assessed. New available technologies are identified and selected to mitigate this new identified scenario. Upon the completion of necessary modifications, facility emergency response procedures are updated comprehensively

Triggered by full surface tank fire incident in one of refinery, detail gap analysis was performed to check the potential emergency scenario and its available mitigation at Senipah Terminal. Based on gap analysis, it was confirmed that initial design of this > 40 year storage tank Facility was not designed to cope with full surface fire but it was designed to mitigate rim seal fire. Based on thorough study, following are improvement of safety and operation aspect of storage tank which already been implemented including: provision of High Capacity Cannon Monitor (HCCM) complete with fire network and foam system improvement, on-line tank surveillance and monitoring system installation, rim gap minimizing and fire embark system improvement to improve existing rim seal firefighting system, spill containment system improvement, foam truck replacement to support firefighting scenario. Site emergency contingency plan was also updated to align with the latest modifications.

Throughout plant lifetime, the emergency preparedness document is live document which should be continuously updated refering to the most recent standard and lesson learnt from the industry. Emergency preparedness is also much linked to the plant design. Any modification on the facility shall be followed by reviewing and updating existing plant emergency management system.
Challenges of the Fluid Modeling and Initialization of a Non-Equilibrium Oil Reservoir: Case Study for Field S in Malaysia
Authors: Hajizadeh Mobaraki Alireza , AL Mudaliar Kokulananda , Salleh Nor Hajjar , Deo Tewari Raj
Published: October 2019

Compositional grading resulting from the gravity segregation in thick reservoirs is a common phenomenon observed especially in volatile oil or gas condensate reservoirs. Same phenomenon is repeatedly encountered for reservoirs with high temperature gradients. It is also not uncommon if compartmentalized reservoirs indicate areal variations in fluid properties. But drastic variation in composition and fluid properties both vertically and laterally in thin to moderate reservoirs where the reservoir seems to be connected based on initial pressure data may denote non-equilibrium conditions. In this study such conditions will be assessed for a Malay basin saturated oil reservoir and the challenges and proposed solutions are presented.

The individual available samples from appraisal and early production system (EPS) development wells covering six stacked sands each comprising of four segments are thoroughly analyzed for quality and reliability. The information from fluid samples including finger prints for hydrocarbons and CO2, is integrated with pressure and full PVT data to characterize the fluid in this field. Reconciliation of PVT and well test data was harnessed to achieve to a set of representative samples for each reservoir/segment while considering reasonable compositional grading and rate of bubble point depression. The samples were then scrutinized for reliable experimental data.

Various alternatives of non-equilibrium initialization vs. defining multiple equilibrium regions with compositional grading were considered. The pros and cons of each method is discussed in this paper and general hints for selecting appropriate approach is given based on type of reservoir being modeled, the purpose of study and available data. It is shown that a fit-for-purpose approach can be adopted to fulfill the requirements of the FDP while trying to reproduce the reservoir behavior. The role of reservoir management and updating the model regularly as per future performance is emphasized.

The non-equilibrium reservoir systems have not been extensively discussed in the industry and limited case studies and corresponding challenges and solutions have been presented. This paper discusses fundamental phenomena encountered in dealing with such systems and presents solutions based on the nature of the problem and project objectives both in theoretical and practical sense and in this regard it is novel.
Validation of Wax Deposition Models Using Field Data of Western Onshore, India
Authors: Agarwal Jatin R. , Dhingra Simran , Shah Neel , Shah Subhash N.
Published: October 2019

Crude oil samples were collected from three-buried gathering lines of Cambay Basin and were characterized in Drilling Cementation and Stimulation (DCS) Research Center, PDPU for their hydrodynamic (Viscosity, Density) and thermal (Specific heat, thermal conductivity) properties along with solubility curve (WAT, pour point and precipitation curve) at Gujarat Energy Research Management Institute (GERMI), PDPU. Theoretical wax mass fluxes for four available wax deposition models were computed using the characterized properties of crude oil samples. Field wax mass fluxes were computed based on field data obtained from the gathering lines and were compared with the theoretical wax mass fluxes. The field data for both 2 km and 5 km long 8 inch ID gathering lines indicated that the crude oil in these pipelines was flowing under laminar flow regime, while for 25km 8 inch ID gathering line it indicated a turbulent flow condition. This leads us to conclude that the presumption of only turbulent flow condition prevails is a myth; both laminar and turbulent flow conditions can occur. Furthermore, a wax mass flux analysis revealed that field wax mass fluxes for gathering lines with laminar flow regime (Re = 200 to 2300) is in good agreement with Film Mass Transfer (FMT) model, while the predictions from Equilibrium Model (EM) and Matzain models are in good agreement with the field data of gathering line with turbulent flow condition (Re = 5400). These agreements are because, for laminar flow case Chilton-Colburn analogy (no-precipitation case) is satisfied which means no precipitation occurs in the mass transfer boundary layer and large amount of wax is deposited radially in the pipe. While, for turbulent flow conditions, the concentration profile is dependent on temperature profile and complete precipitation or instantaneous precipitation occurs in the mass transfer boundary layer. In our study, we made every attempt to obtain reliable field data for comparison with the existing models. The four unique field cases presented here would be useful to researchers in validating their models. In addition, it made us realize that wax deposition is not only an offshore flow assurance problem but also a major flow assurance problem for onshore operations.
Development Well Drilling with Sacrificial Drill Pipe Completion in Fracture Basement Reservoir: Case Study from a Field in Corridor Block, South Sumatra Basin Indonesia
Authors: Permana Budi R , Darmadi Yan , Hamid Fadia , Faisal Ahmad , Tejo Baskoro , Tupamahu Lucien E
Published: October 2019

X gas field is located in the Corridor block of Onshore South Sumatra, Indonesia and operated by ConocoPhillips Grissik Ltd. (CPGL). The field was first discovered in 1994 and started production in 2001. In terms of reserves, X field is the second largest in the Corridor. All production comes from fractured igneous (granite, granodiorite) and metamorphic (meta conglomerate, quartzite, phyllite and marble) rocks of the pre-Tertiary basement.

To date, eight wells have been drilled during the exploration and development program. The most recent development well was the X-8, which was drilled in 2017. The X-8 well was designed to enter the top of the reservoir structure at a location where the seismic amplitude exhibited dimming. Based on analysis of the seismic and well productivity, dimming amplitudes are indicative of faults and fractures.

Historically, exploration, appraisal and development wells drilled in the field did not experience any wellbore stability issues. During drilling of the X-8, wellbore stability and collapse caused significant problems and resulted in the sidetracking of the well three times. Prior to the drilling, it was recognized that depleted reservoir conditions may result in wellbore stability issues, but the rock strength was determined to be sufficient to overcome any wellbore collapse. It would only be necessary to overcome the pressure difference, and this could be done using managed pressure drilling (MPD). Although MPD was implemented successfully, the wellbore collapsed during drilling and before the completion string could be run. Ultimately, the well was completed using the drill string since standard completions were impossible under the time constaints.

An after-action review of X-8 was conducted, and hypotheses were generated to explain the wellbore stability issue in this well. The review included fault interpretation uncertainty, lithology competency, reservoir lithology and geomechanics. Based on this work, two explanations were suggested as the main cause of wellbore collapse. The first explanation is that the top of the basement consists of a weathered zone resulting from exhumation in the Mesozoic. The weathered zone consists of rock material generated by both physical and chemical weathering. The second explanation is shear failure due to reservoir depletion. Both explanations are supported by well data, seismic attributes and current reservoir pressure. In the end, with an understanding of the potential failure mechanism, the last sidetrack was completed by leaving the drill string inside the hole to enable the well to produce. The learnings suggest that drilling through fracture basement reservoir is challenging and with depletion, the reservoirs can be nearly impossible to drill. Casing or liner drilling may be the only solution to successfully drill these types of wells and produce the hydrocarbons.
Tight Carbonate Reservoir Characterization and Perforation Optimization Using Magnetic Resonance in Horizontal Well
Authors: Nugroho Cahyo , Fahmy Mahmoud Fawzy , Ray Dipak Singha , Zekraoui Mohamed , Qutainah Riyad , Ghioca Monica
Published: October 2019

The presented reservoir in this paper is a tight carbonate reservoir with vertical and horizontal heterogeneous properties. In particular, the low clay content in this reservoir gives low gamma ray counts, making difficult the layer identification. In addition, the high-resistivity response of hydrocarbon-bearing pay-zones and of the tight layers make more difficult the identification of the reservoir sweet spots. Slim-hole magnetic resonance (MR) logging was deployed in wash-down mode for identifying reservoir sweet-spots for providing lithology-independent porosity and formation fluid characterization.

The well placement over a deep elongated anticline with steep dips and the lowering of the production liner are challenging. Consequently, the field is being developed using horizontal wells that cut across multiple reservoir layers to maximize reservoir contact and drainage.

MR was acquired with dual wait time enabled T2 polarization to differentiate between moveable water and hydrocarbons. After acquisition, the standard deliverables are partial porosities and permeability index. The porosity is divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). The effective porosity, the permeability index and the permeability-effective porosity ratio were used to evaluate the rock quality. The classification was based on the gradient of the permeability-effective porosity ratio, where a steeper gradient is interpreted as high flow zone, a gentle gradient as low flow zone and a flat gradient is considered as tight baffle zone.

Based on the MR flow units and fluid types (CBW, BVI and BVM), the drilled interval was classified into six compartments of high flow, one compartment of low flow and five tight baffle zones. Accordingly, the perforation plan was optimized to fit the high flow units only. Comparing to the conventional log analysis, MR excluded approximately 700 ft of non-productive reservoirs, leading to more than 250,000 USD cost savings in perforation, drilling time and production optimization.

The well was drilled with a distance-to-bed boundary tool; however, enormous potential exists to use this slim MR tool as a non-radioactive sourceless solution for geosteering through reservoir sweet spots while delivering wells that are more productive safely.
The Influence of Nano-Silicon Material on Clay Swelling Effect
Authors: Rong Xufeng , Wang Yanling , Forson Kobina , Guo Baoyu , Liu Junyi , Wei Mingzhen
Published: October 2019

In traditional production environments, clay expansion in the near wellbore area may hinder drilling and completion operations. However, most of the above stabilizers cannot meet the actual requirement because the general clay stabilizer cannot migrate through small voids, and can also cause damage to the environment and be very expensive. Herein the behavior of nanoparticles in stabilizing clay particles and the condition for reducing the clay swelling and reservoir damage are investigated.

The adsorption characteristics of nanoparticles on the core surface were studied by adsorption experiments and SEM. Displacement experiments of cores was conducted to discuss the migration behavior of nanoparticle inhibitors. In addition, the Malvern Zetasizer light reflectometer was employed to measure the electrokinetic potential of nanoparticles. To obtain a nanoparticle dispersion system, the dynamic dispersion measurement information of nanoparticle size distribution was collected. In the stability, by controlling the temperature, pH, pressure and other factors, the effects of these factors on the stability of the clay are investigated to obtain the mechanism of action of the nanoparticles.

The core piece was immersed in 1g/L nano-liquid. After adsorption for a period of time, it was observed by SEM that the hydrophobic nanoparticles could form an adsorption layer on the core surface and show a strong hydrophobicity. The nano-electromotive potential is stable at +38.2mV and −36.0mV, indicating that the dispersion is very stable. The dynamic dispersion measurement surface size of nanoparticle dispersion is much smaller than the typical pore and pore channel size in most reservoirs. The microparticles are dispersed and injected through a filter device with a pore size of 200 nm and all of them are dispersed through the core. There is no residue in the filter device, thereby achieving effective migration in the core. It can be concluded that the adsorption effect is stronger under alkaline conditions when the adsorption amount is only reduced by 10% at 950 °C. This is not affected by the pressure factor and also the adsorption effect is stable.

The action of mechanism between nano-silicone material and clay is obtained, and different factors are investigated to find out the prospect of nanoparticles in improving clay stability and reducing the reservoir damage.
Infill Wells Placement in High Water-Cut Mature Carbonate Field with Simulation Opportunity Index Method
Authors: Bernadi Bondan , Silalahi Eli Saut , Reksahutama Agun , Miraza Donny
Published: October 2019

Despite intelligent method such as numerical simulation model has been used, identifying areas or zones that still holding high potential of production still becomes the most challenging aspect in the development of mature carbonate oil field with high water-cut; especially coupled with the lack of required important data to generate such appropriate model. A practical method to explore the sweet-spot areas within the field is then introduced, hereinafter called "Simulation Opportunity Index" (SOI) based on techniques already established in the industry.

SOI is an integration of three (3) independent components whereas each of them is normalized to produce indexes that represent reservoir-permeability thickness, movable oil and reservoir pressure from a historically-matched dynamic model. The method utilizes the historically-matched simulation model in which the water saturation from the dynamic model is calibrated with the recent acquired cased-hole logging saturation log to improve the confidence level. The cased-hole logging saturation log results are treated as the only ground truth of the current saturation within the reservoir thus it plays important role to reduce the model uncertainty and to simplify the workflow in efficiently short time. The SOI method is hence used as an invaluable tool to spot areas for further development such as infill wells. The workflow to produce the potential areas within the reservoirs is discussed in this paper including comparison to see infill wells performance by using both conventional and SOI approaches.

Notwithstanding lesser producible oil reserves due to denser-placed infill wells over time and high water-cut of the field >95%, the method after implementation in numerical simulation is capable to screen-out a number of sweet-spot areas for infill wells placement in the largest mature oil field of RH PetroGas (Basin) Ltd concession in Salawati basin, onshore West Papua, which can be ranked thereupon for execution after sensitivities and economics analysis. The infill wells are still the most technically-favourable development scheme to hold oil production decline about 6%/year in the field. Thus, it is essential to place the infill wells within the most optimum locations that would yield maximum sweep efficiency, acceleration of the expected recovery or incremental increase of the Estimated Ultimate Recovery (EUR) from such heterogeneous reservoirs.

The application of SOI methodology in numerical model is helpful to practically identify areas or zones with high oil potential due to non-uniformity volumetric sweeping efficiency in carbonate reservoirs in relation to their tremendous heterogeneity, variable wettability and dual pore network.
Real-Time Production Logs Surveillance: Automated Workflow Technology Allows Synthetic Sensing of Oilfield Downhole Production
Authors: Bawazir Mustafa , Dallag Mohammed , Shukla Sourabh
Published: October 2019

One goal for oil fields of the future is acquiring continuous and on-demand data as required for field and reservoir management. Synthetic time-lapse production methods are becoming a way of providing this information at and away from wells. Time-lapse production log data acquired over oil fields is used to monitor water sweep in the reservoir. Production logs provide a direct measure of the fluid flowing downhole and detect the unwanted fluid entries. In field applications, this advanced scanning of fluid profiling successfully derisked several infill well locations and identified new workover candidates and drilling opportunities in the fields.

Synthetic time-lapse production logging is a useful complement to understanding reservoir heterogeneity and complexity through tailored synthetic and real data integration. A computer-based workflow has been developed to automate the downhole production flow profile. Production performance of the well is assessed, considering the dynamic time-lapse logging data. A synthetic flow profile is constructed to show the change in water production signature, and the well is further examined if it undergoes remedial actions. Reservoir characterization is a continuous process during the life of the oil field. As new data are available, the model is updated and contains more details. The incorporation of all data allows increased accuracy and reduced uncertainty in characterizing the reservoir.

The proposed methodology requires the acquisition of dynamic production logging data to establish a solid workflow and validate the model. Uncertainty can be eliminated with the acquisition of additional production logs. Recommendations for improvement of the current well condition can be made to reduce the well water cut and improve oil production from the well. Consequently, well classification and candidate selection for workover can be achieved. The results of this work demonstrate the strength of applying multidisciplinary team efforts to develop automated workflows that are relevant to reservoir and production engineers who deal with complex reservoirs with numerous wells.
Reservoir Fluid Sample Decontamination: Application Example
Authors: Altowilib Ali R. , Sequeira Daryl S. , AlOtaibi Fawaz M. , Sahl Ahmed M.
Published: October 2019

An acquisition of representative reservoir fluid samples is important for reservoir management and development. During overbalanced drilling, the high hydrostatic pressure causes mud filtrate invasion into the reservoir. This makes the process of acquiring representative reservoir fluid samples challenging due to the miscibility of Oil-Based Mud (OBM) filtrate with the reservoir fluid. The presence of OBM filtrate impacts the characterization of the reservoir fluid, resulting in inaccurate and not representative PVT laboratory measurements. PVT data generated out of contaminated samples should be avoided as they have the potential of harming field development plans.

In this study, OBM level in contaminated samples was quantified and their compositions were restored through skimming and subtraction techniques. Consequently, the key fluid properties of the decontaminated fluid were successfully predicted through an Equation of State (EOS) software.

The results demonstrated the impact of OBM filtrate on bubble point pressure and heavy-end properties, as concluded by the EOS modelling software, which compared the phase behavior properties of the contaminated and decontaminated fluids. Subsequently, modeled properties like Formation Volume Factor (Bo), Gas-Oil Ratio (GOR), API gravity, and mixture density were all compared to the measured fluid properties of clean fluids. Additionally, the capability and robustness of each decontamination methods were confirmed against the measured original clean composition.
Augmenting a Conventional Gas Lift System via Annulus Injection of Homogenized Foam and Gas: From Paper Plan to Execution
Authors: Kunasekaran Sarran Raaj , Ismail Syahezat , Yahia Zaidil , Naafs Derk , Koyyalamudi Lakshmi Narayana , Elias Noor Elfirdaous , Abu Bakar Azfar Israa , Ramba Akok , Othman Abdullah
Published: October 2019

BKR is a producing field, offshore Malaysia with almost 100 strings producing either naturally or utilizing gas lift as its primary artificial lift method. BKR being a mature field with increasing watercut production and declining reservoir pressures, experiences gas lifting issues such as an ever increasing lift gas demand and deteriorating lift gas utilization factor (GUF). To improve the gas lifting efficiency a pilot project utilizing foam to assist gas lifting was attempted.

Based on a literature studies, foam assisted gas lift is expected to be able to reduce the gas lift consumption by gas lifted wells, as well as further improving the lifting performance of gas lifted wells by introducing a foaming agent into the flow stream. After performing the feasibility studies, 2 wells were identified at BKR field for the pilot execution, based on the candidate screening criteria.

This paper presents the problems and opportunities which led to the foam assisted gas lift pilot trial in BKR field, as well as the trial results and key learnings. The theoretical background of the approach and few case studies done at other fields previously are summarized. It also details candidate screening criteria, chemical/foam lab tests to ensure foam performance and compatibility to the well system, evaluation approach, as well as potential application methods.

The second part of the paper discusses the planning and actual job implementation which includes logistics, treatment well on paper exercise, well and chemical surveillance plan and detailed treatment procedures.

The result of the pilot will be elaborated in detail in the paper covering the well's baseline production rate and production well test trends along the execution phase, pressure and temperature data collected, lessons learnt during pilot execution and potential way forward for the next pilot.

Based on the field trial results, the foam assisted gas lift approach has proven to be one of potential solutions to overcome gas shortage and poor GUF problems in the field. The results were very promising with almost a 100% improvement in production in one of the candidates. These results meet the goal of the pilot implementation which is to find a technology with good results with minimum expenditure. Nonetheless, several operational and logistic issues need to be addressed to have sustainable results, as well as prudent cost management.
Initiate Digital Oil Field Application at Mature Offshore Oil Field in South East Sumatera, Indonesia
Authors: Waskito Lucky Bagus , Vidrianto Marda , Cahyoniarso Bambang
Published: October 2019

In recent years the Industry are busy talking about the subject of mature field development, lots of opportunity and approaches has been applied to enhanced reserves and production, in the other hand efficiency and technology also can be the answer of the subject, big volume of data at high frequency produced every second, searching relevant information from those data are quite complex and time consuming, not to mention processing huge data volume for many particular solution, it is complicating the decision making process. The objective of this paper is addressing the process and technical challenges in building digital oil field platform at offshore mature asset to speed up the decision making and make operation activities more efficient.

The design of the workflows and business processes are tailored to accommodate any kind of input across all the disciplines from reservoir, production, drilling and completion to produce output as desired. The early stage process of building digital oil field system starts from data utilization that produced by downhole sensors, it is attached with Electric Submersible Pump that installed at all wells. The data transformed into information for real-time production monitoring & optimization, these workflows allow production enhancement by continuous monitoring of production parameters such as pressure, temperature, flow rates, choke settings and target. Analysis of these parameters carried out using trend, in case of anomalies happens in the process, the system will provide the information and possible solution.

Digital Oil Field technology can be a game changer for the mature field development in the future. Integration of technology, process and people together to achieve financial objective is the major initiative of digital project, but applying digital technology is easier said than done as our companies are finding out, in our case we faced several difficulties that need time and complex algorithm to find the solution. But this early stage of digital oil field will answer the challenges in managing offshore mature asset efficiently, because it will reduce downtime, optimize production, and reduce cost. The future development of digital oil field in SES Block will allow all parties to grab the information in present time and also the forecast prediction of asset performance in the future.

SES Block is a mature oil field that has produced for more than 50 years, peak production rate almost reached 250,000 BOPD in 1991, while current production rate around 30,000 BOPD. One of the major problems in this asset is the excessive use of Electric Submersible Pump that generates high operating cost, this is the reason why efficiency during daily operation process using digital oil field application is smart answer to reduce cost and optimize company profit.
Comprehensive Study of the Oda Corrected Permeability Upscaling Method
Authors: Haridy Mohamed Galal , Sedighi Farzaneh , Ghahri Panteha , Ussenova Kamshat , Zhiyenkulov Murat
Published: October 2019

Choosing an appropriate technique for upscaling the permeability of the discreet fracture network (DFN) model is vital for maximizing recovery from naturally fractured reservoirs (NFR). Flow -based upscaling is accurate, yet it is computationally expensive. Analytical (i.e. Oda method) upscaling is computationally efficient; however, it is only accurate for well-connected fractures. The objective of this paper is to analyze the performance of the newly developed Oda corrected method which addresses issues associated with previous upscaling methods.

This research was executed by using a commercial numerical simulator and by using data set from the Teapot Dome Reservoir. Furthermore, DFN modeling was used to generate different realizations for the fracture network. Consequently, sensitivity analysis was performed through a realisti c uncertainty quantification to generate a base case and 6 different DFN realizations. The main parameters used for this study are fracture length and intensity. Afterwards, the fracture permeability corresponding to each DFN realization was upscaled using the above-mentioned methods. Finally, differences between the upscaling methods were evaluated and analyzed using flow-based upscaling as the criterion.

Indeed, the analysis revealed that the new Oda corrected method can calculate the equivalent permeability tensor with adequate accuracy. However, it overestimates the permeability when fracture networks are below the percolation threshold and/or when fractures length is large. Hence, this method is recommended for networks with moderate to high intensity. Furthermore, it has been deduced that fracture length has a great impact on the connectivity of fractures, albeit its effect on permeability is limited by fracturing density. Additionally, it has been found that the length of fractures has an immense impact on the anisotropy ratio and control the occurrence of water bypassing, which were not captured by the Oda method.
Comparative Evaluation of the Effectiveness of Single-Component and Multi-Component Hydrocarbon Additives for Bitumen Recovery by Steam Assisted Gravity Drainage
Authors: Selvakumar Bhuvanesh , Gates Ian , Maini Brij
Published: October 2019

The inherently high viscosity of bitumen makes SAGD the ideal technology for in-situ recovery of these unconventional hydrocarbon deposits. Its conceptual simplicity and proven performance in the field have directed research to explore new opportunities to further improve its recovery efficiency and minimise its environmental footprint. Solvent addition to steam in a SAGD process makes the thermal and solvent dilution effects on oil viscosity act together in improving the bitumen recovery. Various experimental, numerical and pilot studies have shown the incremental benefit of solvent co-injection in accelerating the oil recovery at reduced steam-oil ratio compared to steam alone injection. The objective of this work was to evaluate the effectiveness of different single-component and multi-component additives for improving the SAGD performance.

Among the various process variables, the optimal solvent design and the injection pressure play influential roles in determining the process efficiency, as they directly affect the phase behavior of the system. This paper uses numerical simulation to examine the solvent-SAGD mechanisms and presents a comparative analysis of single and multi-component solvent injection at low and high operating pressures. A lab scale physical model saturated with Athabasca bitumen, used in an earlier experimental study, was adapted to a simulation model for this purpose. After tuning the numerical model by history matching the physical model experiments, it was used to compare the benefits of co-injecting different solvents with steam at two different operating pressures. A range of single component solvents (C4, C5 and C6) and a multi - component gas condensate were aevaluated for low and high-pressure injection scenarios.

The results show that all tested solvents reduce the steam oil ratio and enhance the rate of oil production. The relative performance of different solvents is affected by the innate bitumen viscosity and the operating pressure. With lower bitumen viscosity, C4-steam co-injection outperformed C5, C6 and gas-condensate addition for both low- and high-pressure ES-SAGD cases. However, the performance of heavier solvents was better at higher operating pressures due to their relative ease of condensation, which enhances their interactions with bitumen.
Acquiring Offshore Project Sanction during Low Oil Price Environment: Rejuvenating Reservoir with Depleted Reservoir Energy via Innovative Low Capex Gas Injection Project
Authors: Awang Pon M Zaim , Hongmei Gao , Chee Hui Sim , Abdul Aziz Shahrizal , Abdulhadi Muhammad , Van Tran Toan , Anuar M Azlan , Jacobs Steve , Munandai Hasim , Khalid Aizuddin , Kumar Ashok
Published: October 2019

Maturing a secondary recovery project in an offshore multi-fault complex reservoir is challenging because considerable investment is required, especially in a low oil price environment and/or when the asset can no longer produce. However, an 85% reduction in cost with no reduction in reserves was achieved for such a reservoir through de-risking the opportunity and revising the development concept, allowing the project to be sanctioned during a low oil price environment.

A water injection project with an estimated cost of 165 MMUSD was initially envisaged during the feasibility stage to increase the oil recovery of a depleted reservoir, and contractual expectations were agreed accordingly. This is due to the availability of seawater offshore and water injection being the standard improved recovery approach in the region. Without adhering to the familiarity, a reservoir simulation study was performed comparing multiple options of secondary recovery. The reservoir simulation indicated that gas injection would provide higher incremental recovery while the investment can be significantly reduced by utilizing the existing gas lift system as a gas injection system.

Several improved oil recovery schemes were evaluated with the history matched dynamic model to address the depleted energy. This includes water dumpflood, water injection, and gas injection with recovery factors of 32%, 56%, and 58%, respectively, in comparison to the depletion drive recovery factor of 30%. The gas injection scheme provides the highest recovery factor and expected fastest response and thus was prioritized as the main focus over water injection. The existing gas compressor with ullage, gas source from current associated gas production, and existing idle wells are key enablers for the project. The existing assets also enable the acceleration and further de-risking by a pilot gas injection before drilling infills.

The paper highlights the numerous examples of cost-saving initiatives while maximizing the oil recovery from the reservoir. This value-focused approach enabled the project to be sanctioned during a period where most offshore improved recovery projects were abandoned due to the low oil price.
Sustainability Initiative: Integrating Environment and Social E&S Requirements into a Front End Loading FEL Management System
Authors: Asmoro Trian Hendro , Prabowo Hirmawan Eko , Prayascitra Adearty
Published: October 2019

All project requirements should completely be defined in the planning phase, thus it seen as the most critical activity in a project’s lifecycle. Sustainability aspects for an Exploration & Production (E&P) project need to be included starting from planning phase to identify and manage project risks particularly in Environment and Social (E&S) sides. In fact according to a study, some key principles of sustainability have actually been adopted in the E&P activities.

Meanwhile, Front End Loading (FEL) is a structured approach to increase the predictability of the project outcomes by narrowing down the risks from all technical, commercial, legal, E&S and other aspects. It uses a stage gate system in order to assure the project prior to authorization and to move on to the next step of investment decision, and a typical FEL method has widely implemented in the E&P business across the globe using different company name.

One of set of requirements addressing sustainability aspects in a project is that Performance Standards (PS) developed by IFC (International Finance Corporation). It has 8 comprehensive elements and internationally-accepted standard of E&S practices which encourages transparency and positive contribution to environment and community. In addition, adopting IFC PS has been mostly becoming compulsory nowadays when dealing with financial institutions to support a project financing to be considered as green financing.

This paper will explore how to integrate E&S requirements taken from IFC PS, such as E&S Impact Assessment (ESIA) and E&S Management System (ESMS) into a FEL management system for an E&P company operated in Indonesia. It will discuss the gaps between sustainability features in IFC PS and Government regulation, and finally bridge them properly. To conclude, it is very important to include sustainability requirements earlier in the project’s lifecycle to help manage E&S risks in the project and improve the outcomes.