Ho, Yeek Huey (Petroliam Nasional Berhad, PETRONAS) | Ahmad Tajuddin, Nor Baizurah (Petroliam Nasional Berhad, PETRONAS) | Elharith, Muhammed Mansor (Petroliam Nasional Berhad, PETRONAS) | Dan, Hui Xuan (Petroliam Nasional Berhad, PETRONAS) | Chiew, Kwang Chian (Petroliam Nasional Berhad, PETRONAS) | Tan, Kok Liang (Petroliam Nasional Berhad, PETRONAS) | Tewari, Raj Deo (Petroliam Nasional Berhad, PETRONAS) | Masoudi, Rahim (Petroliam Nasional Berhad, PETRONAS)
Managing a 47-year brownfield, offshore Sarawak, with thin remaining oil rims has been a great challenge. The dynamic oil rim movement has remained as a key subsurface uncertainty especially with the commencing of redevelopment project. A Reservoir, Well and Facilities Management (RWFM) plan was detailed out to further optimize the development decisions. This paper is a continuation from SPE-174638-MS and outlines the outcome of the RWFM plan and the results’ impact towards the development decisions, such as infill well placement and gas/water injection scheme optimization. Key decisions impact by the RWFM findings are highlighted.
One of the RWFM plans is oil rim monitoring through saturation logging to locate the current gas-oil contact (GOC) and oil-water contact (OWC). Cased-hole saturation logs were acquired at the identified observation-wells across the reservoir to map time-lapse oil rim movement and its thickness distribution. Pressure monitoring with regular static pressure gradient surveys (SGS) as well as production data, helped to understand the balance of aquifer strength between the Eastern and Western flanks. Data acquisition opportunity during infill drilling were also fully utilized to collect more solid evidences on oil rim positions, where extensive data acquisition program, including conventional open-hole log, wireline pressure test, formation pressure while drilling (FPWD) and reservoir mapping-while-drilling, were implemented.
The timely collection, analysis and assimilation of data helped the team to re-strategize the development / reservoir management plans, through the following major activities: Re-strategizing water and gas injection plan to balance back oil rim between the Eastern and Western flanks, through deferment of drilling water injectors, optimization of water and gas injectors location and completion strategies due to stronger aquifer encroachment from east and south east. Optimizing infill wells drainage points where 2 wells were relocated based on cased-hole logs, as the first well original location was swept and the second well was successfully navigated through the oil rim using reservoir mapping-while-drilling techniques coupled with cased-hole log results. This resulted in securing an oil gain of 4000 BOPD from these 2 wells. Optimizing infill wells location and planning an additional infill well with potential additional oil gain of approximately 2000 BOPD. The understanding of current contact and aquifer strength from the surveillance data assisted in identifying fit-for-purpose technology for the new wells such as the application of viscosity-based autonomous inflow control device which assisted in placing the well closer to GOC due to the observed rapid rising of water table, this will help sustaining the well life.
Re-strategizing water and gas injection plan to balance back oil rim between the Eastern and Western flanks, through deferment of drilling water injectors, optimization of water and gas injectors location and completion strategies due to stronger aquifer encroachment from east and south east.
Optimizing infill wells drainage points where 2 wells were relocated based on cased-hole logs, as the first well original location was swept and the second well was successfully navigated through the oil rim using reservoir mapping-while-drilling techniques coupled with cased-hole log results. This resulted in securing an oil gain of 4000 BOPD from these 2 wells.
Optimizing infill wells location and planning an additional infill well with potential additional oil gain of approximately 2000 BOPD.
The understanding of current contact and aquifer strength from the surveillance data assisted in identifying fit-for-purpose technology for the new wells such as the application of viscosity-based autonomous inflow control device which assisted in placing the well closer to GOC due to the observed rapid rising of water table, this will help sustaining the well life.
This paper highlights the importance of data integration from geological knowledge, production history, reservoir understanding and monitoring through regular SGS and time-lapse cased-hole saturation logging, coupled with extensive data acquisition during infill drilling. By analyzing and integrating the acquired data, project team can then confidently re-strategize and successfully execute the complex mature oil-rim brownfield redevelopment.
Morales, Adrian (Chesapeake Energy Corp.) | Holman, Robert (Chesapeake Energy Corp.) | Nugent, Drew (Chesapeake Energy Corp.) | Wang, Jingjing (Chesapeake Energy Corp.) | Reece, Zach (Chesapeake Energy Corp.) | Madubuike, Chinomso (Chesapeake Energy Corp.) | Flores, Santiago (Chesapeake Energy Corp.) | Berndt, Tyson (Chesapeake Energy Corp.) | Nowaczewski, Vincent (Chesapeake Energy Corp.) | Cook, Stephanie (Chesapeake Energy Corp.) | Trumbo, Amanda (Chesapeake Energy Corp.) | Keng, Rachel (Chesapeake Energy Corp.) | Vallejo, Julieta (Chesapeake Energy Corp.) | Richard, Rex (Chesapeake Energy Corp.)
An integrated project can take many forms depending on available data. As simple as a horizontally isotropic model with estimated hydraulic fracture geometries used for simple approximations, to a large scale seismic to simulation workflow. Presented is a large-scale workflow designed to take into consideration a vast source of data.
In this study, the team investigates a development area in the Eagle Ford rich in data acquisition. We develop a robust workflow, taking into account field data acquisition (seismic, 4D seismic and chemical tracers), laboratory (geomechanical, geochemistry and PVT) measurements and correlations, petrophysical measurements (characterization, facies, electrical borehole image), real time field surveillance (microseismic, MTI, fracture hit prevention and mitigation program through pressure monitoring) and finally integrating all the components of a complex large scale project into a common simulation platform (seismic, geomodelling, hydraulic fracturing and reservoir simulation) which is used to run sensitivities.
The workflow developed and applied for this project can be scaled for projects of any size depending on the data available. After integrating data from various disciplines, the following primary drivers and reservoir understanding can be concluded. At a given oil price, optimum well spacing for a given completion strategy can be developed to maximize rate of return of the project. Many operators function in isolated teams with a genuine effort for collaboration, however genuine effort is not enough for a successful integrated modelling project, a dedicated multidisciplinary team is required.
We present what is to our knowledge, one of the most complete data sets used for an integrated modelling project to be presented to the public. The specific lessons from the project are applied to future Eagle Ford projects, while the overall workflow developed can be tailored and applied to any future field developments.
Christian Bos, Senior E&P Reserves and Decision and Risk Expert with TNO-NITG, gave a presentation in December on "Why the E&P Industry Is Waiting for a New Generation of Petroleum Business Engineers" to the Netherlands young professionals group. He said there are conflicts between models that describe the Earth as accurately as possible and models tailored to E&P business decisions. The first category tends to be highly detailed, whereas the latter category generally is more probabilistic, based on integrated data, and contains less detail. The main focus of the presentation addressed determining the best approach to take in building models that support E&P business decisions, and how the bias in decisions that has characterized the industry in the past can be prevented. Looking at stock market returns, it is clear that the E&P industry has underperformed other industries in North America, he said.
Digital Transformation across the geosciences and engineering domains is driven by the need to share data of increasing complexity and quantity as part of a distributed workload involving operators, partners, service companies and consultants. Unconventional plays pose an additional challenge since a large number of wells need to be planned, to be drilled in days. Companies operating multiple rigs, fracking crews and workover teams have a significant, time-constrained workload that requires rigorous and efficient execution.
To support a broadening of collaboration among all actors involved, such a work context would require all users to operate the same software suite, with the ability to periodically synchronize data repositories or work concurrently in a common cloud environment. However, the reality is that different companies or departments within a company use different software systems. The push to apply more analytics, new modeling technologies or broader, multi-disciplinary workflows to unconventional reservoirs, with software tools often sourced from new third-party providers, adds to the burden of more complex data flows and the concomitant data verification required from data consumers.
File formats exist to transfer specific data objects, for well data (e.g. LAS, DLIS), grid data, etc.. between different software platforms. These formats package the information for one data instance such as one well. With large unconventional resource play projects drilling hundreds of wells a year while managing production from hundreds more, individually writing and reading files for all new or updated wells and sharing this data across multiple systems is labor-intensive and prone to errors or omissions. This in turn puts the burden on the recipient of the data to verify data correctness and completeness.
An industry consortium has developed and published a data exchange standard that packages all the data pertaining to a hydrocarbon reservoir system. This includes subsurface measurements, interpretation, drilling, completion and production data such that a complete project can be exported from one system and read into another in a single pass. The process supports a full charting of data items and their metadata. This drastically reduces the workload at both ends of the transaction while offering significantly better guarantees that the set of data is complete and correctly referenced.
This has been proven in a full-scale live demonstration involving 6 different software systems each executing a step in a reservoir model enrichment workflow and writing out the data ready for the next software system to ingest it. The total time including the workflow steps and read-write operations totaled 45 minutes, significantly less time than would be needed to execute such a workflow using traditional I/O processes and file formats, and at considerably less risk of errors or omissions.
Jamaludin, Izzuddin (PETRONAS Carigali Sdn Bhd) | Mandal, Dipak (PETRONAS Carigali Sdn Bhd) | Arsanti, Dian (PETRONAS Carigali Sdn Bhd) | Dzulkifli, Izyan Nadirah (PETRONAS Carigali Sdn Bhd) | Zakaria, Nurul Azami (PETRONAS Carigali Sdn Bhd) | Mohamad Salleh, Salhizan (PETRONAS Carigali Sdn Bhd) | Ahmad Hawari, Saiful Adli (PETRONAS Carigali Sdn Bhd) | Mohd Azkah, Mohd Zubair (PETRONAS Carigali Sdn Bhd)
Data acquisition remains one of the crucial activities to be consistently executed throughout field life for any oilfield development. Significant operating expenditure (OPEX) is allocated each year to understand reservoir performance, thus reduce uncertainties and enable optimizations. This paper aims to highlight the issues faced during simulation model history matching (HM) process of a waterflood reservoir, including understanding of depositional environment and production data integrity. The output is utilized to improve recovery factor (RF) via infill opportunities and water injection optimization.
Field A has run a second shot of 3D seismic in 2006 (first in 1995) and processed into a time lapse, 4D seismic. In 2014, a cased hole logging campaign utilizing the high precision temperature, spectral noise logging (HPT-SNL) tool has been completed to check the integrity and flow contribution of 12 wells in Reservoir-X. Within the same period, a pulse pressure testing (PPT) was carried out to verify the communication between wells, in addition to acquiring regular surveillance data which helped to improve reservoir simulation study.
The 4D seismic helped to understand the areal waterflood front movement and explained the water cut trend anomaly in an updip well which experienced earlier water breakthrough than near downdip producers. Moreover, it helped to identify a bypass oil zone which can potentially be an infill location. As most of the wells are on dual string completion, the HPT-SNL campaign helped to improve production allocation of multi stacked reservoirs as well as identify problematic wells which required rectification jobs. The PPT assisted in identifying a baffle zone to explain the poor pressure support observed in some producers in the south from the nearby water injectors. All data interpretations were incorporated into final HM model which subsequently identified infill locations and the reservoir management plan (RMP) was successfully revised. An infill program was executed in 2015, which successfully secured additional EUR of ~9 MMstb. Based on the studies and outcome of the infill campaign water injection optimization helped to improve production and added ~2 MMstb reserves, through voidage replacement ratio (VRR) optimization and oil producer (OP) to water injector (WI) conversion. With these efforts, team could successfully project RF of >55%.
This case study demonstrates how acquiring focused surveillance data and their effective integration in performance analysis in simulation study helps to reduce uncertainties, unveils infill opportunities, improves production injection optimization and thus helps to improve the recovery factor in brown fields.
An automated wireline milling solution targeted for removal of wellbore obstructions of a varying type, from scale to metal, with built-in capabilities of autonomous cruise navigation between consecutive obstacles, is presented. This paper highlights design features that made a step change in the efficiency and usability of milling services.
Control challenges are still common in downhole milling technology. Changes in milling target composition, cuttings accumulation around the target, drag forces from production flow, and other variations can reduce system efficiency and result in lost time or failed interventions. In the case of wireline milling technology, inclusion of intelligent on-board electronics in the downhole equipment presents an opportunity to actively control the milling process to optimize rate of penetration and implement additional protections to reduce operational risk. We describe a robotic toolstring that automatically and independently controls a wireline tractor using real-time feedback from a milling cartridge and other on-board sensors. Embedded control algorithms implement intuitive workflows derived from the combined experience of multiple experts in well intervention.
With this automated wireline milling system, the user can initiate the milling process by defining certain milling parameters and then can monitor progress in real time while the downhole robotic tool regulates weight on bit and the milling motor. This new automated downhole control system significantly improves torque-on-bit and weight-on-bit controls yielding superior performance, such as rate of penetration and usability. Dynamic load conditions are handled in a high-speed distributed control loop downhole to get most of bit torque capacity across the entire speed range defined by the motor power curve. Tractor push force is adjusted quasi-instantaneously with changes in cutting conditions. Control responsiveness along with software solutions for tracking of motor stall preconditions and a torque limiter greatly reduce the occurrence of motor stalls arising due to the bit wedging in highly reactive targets. With stall avoidance and an automatic backing-off feature to reengage the bit in case of a sporadic torque spike, direct involvement of an operator is significantly minimized compared to the previous tool generation. Head-voltage stabilization is another factor positively impacting the overall power stability and performance of electromechanical tools downhole. Safety features are also in place to prevent cable twisting and protect assets from overcurrent and overtemperature conditions.
The progressive design of the automated milling tool boosts operational efficiency and autonomy, minimizes human mistakes, and reduces risk of getting stuck during the service. Case histories demonstrate the first field jobs and system integration tests performed with this new tool.
North Kuwait has planned EOR activities to boost ultimate recoveries in multiple reservoirs. The reservoir with the highest priority on the EOR activity Gantt chart is Alkaline Surfactant Polymer (ASP) flood for Sabiriyah Mauddud due to significant incremental recovery estimated based on past SWCT tests. Prior to the initiation of ASP injection, slated pilot area is under intensive plumbing for insights into the inter-well connectivity. The paper proposal aims to share the actions taken up, analysis done and tracking of dynamic data for the area located within & adjacent to the EOR pilot area.
Data acquisition for the pilot area wells (4 injectors; 2 observation wells & 1 producer) has been done in two phases — (a) during the drilling of the wells, cores/ RFT pressures/ Log suites/ PVT samples have been taken and (b) during the injection of sea water into the EOR pilot injectors, time lapse pressure-production data/ surveillance information & tracer sampling/ analysis have been done to understand the inter-well connectivity; flag the uncertainties and de-risk the EOR pilot as a preparatory background for studies & ASP injection.
Connectivity between wells within the pilot & surrounding area under active water flood has been established. Pathways for quick fluid/ flux movements have been identified and calibrated with the petrophysical data. Tight zones or compartments within the pilot area have been examined. Uncertainty regarding thief zones within & outside the pilot area has been evaluated. A comprehensive data integration indicates that continuing with ASP injection will be optimal, with minimal losses/ escape to the area outside the 5-spot EOR pattern.
De-risking the upcoming ASP injection via proper data acquisition, interpretation & integration during the preliminary water flood flushing stage is one of the best industry practice.
Field K1 as part of AA Tight Gas Cluster features significant variability in the fluid properties, concluded through PVT, well test as well as geochemical measurements. Following an extensive data acquisition program that was conducted at the beginning of the project, a multi-disciplinary review and integration of data was carried out in order to adequately characterize the fluid distribution across the field.
Several analyses were employed to understand the characterization of the fluid distribution through geochemistry analysis, compositional gradient analysis and lateral fluid investigation.
Gas samples and mud gases were collected during drilling and analyzed for gross composition and stable carbon isotope for geochemical analysis purposes. Condensates were collected and analyzed for gross composition, sulfur content and isotopic analyses. Analyses of both fluid types aimed at gathering reliable information in terms of source type and thermal maturity of gases. The large number of data points from high resolution sampling of mud gases allowed for a more confident examination of charge history and communication of the Upper Amin Formation across the cluster of fields.
The gas and condensate samples were taken after well completion for further PVT analysis. Gas composition, temperature, fraction of liquid drop-out and measured Dew Points suggested complex reservoir fluid and genetically different behavior with a contrasted fluid signature across Field K1. Plotting the fluid composition, phase envelopes, as well as Dew Point gradient supported application of a complex-fluid modeling together with segmentation.
The understanding of the fluid behavior is important for the reservoir description as well as the overall development plan of Field K1. The impact on the development plan includes: missing condensate recovery opportunity, on-plot and off-plot facility design, overall gas and condensate recovery factor per well, and the sequence of development.
This new analysis resulted in an upward update in resource volume estimation of Field K1. Well placement and drilling sequence optimization were derived as the positive outcome of this exercise.
One of the main challenges in the execution of regional studies is the integration of large amounts of data coming from different sources and different disciplines. Even within the geophysical domain, integration of thousands of 2D seismic lines and dozens of 3D seismic volumes is a very demanding task. The aim of this paper is to provide a description on the use of fast track methodologies for the integration of 3D and 2D seismic data at country level for regional studies.
This approach relies on a pragmatic way of merging seismic, processing data as point sets instead of traces, providing the flexibility of handling seismic information inside the geomodelling and geostatistical domain, where a grid of points can be resampled, reoriented, and ultimately merged into any desired geometry and resolution. The technical challenges include different spatial sampling, grid orientations, frequency contents and event timings. A preconditioning step has been included in the workflow in order to homogenize the data into a common ground, addressing compatibility issues of the different vintages through amplitude scaling, noise reduction and frequency balancing.
Merging in a practical approach different 2D/3D seismic data sets into a single volume reduces drastically the amount of time spent in the data analysis and interpretation of geological features at regional scale. In this case of study, the workflow enables a feasible path for merging all seismic data acquired in Abu Dhabi over the past seven decades. The integrated volume helps geophysicists and geologists to carry out better seismic interpretations and perform proper structural analysis and prospect assessments. Finally, the seismic data has been integrated into a unique survey by interpolating the 2D and 3D seismic data to fill the gaps and generating a pseudo 3D survey at country scale. This regional scale single 3D seismic data allows better understanding of the geological and structural trends present in Abu Dhabi.
This innovative approach offers a major advantage for regional data integration, expediting subsequent stages of seismic interpretation and description of the geological features at large scale for exploration assessments, prospect generation and 3D reservoir characterization.
A huge amount of data is made available during well operations (surface and downhole logging data, lithological reports, drilling reports, equipment data,.). An integrated analysis of these multi source data provides highly valuable information for future wells engineering and planning in term of well problems investigation, performance enhancement and, ultimately, cost reduction by anticipating and reducing risks.
The use of a "big data" solution consolidating these multiple sources allows the creation of numerous analytics both on single well and group of offset wells. Particularly, the interpretation of surface logging data through the automatic recognition of operating sequences, when put together with other data sources including standard daily reports, provides a much higher granularity than traditional reporting.
Every operation is accurately measured through objective and detailed KPIs (ROP, tripping speed, weight to weight, connection time, etc.). Technical and performance issues are easily evaluated allowing a better understanding of their root causes, anticipating and avoiding the occurrence of these problems in the next wells and measuring activities and operations potential improvement.
This process helps reducing drilling costs through entire well lifecycle:
The calculation of the technical limit and the implementation of the lessons learned that can emerge from the analysis allows to increase the performance on the overall drilling phase through the reduction of the Invisible Lost Time. ILT are usually around 25% of all the drilling operations. This increase of performance has been measured on a series of drilling campaigns in a range from 6% to 8% time saving. The calculation of impartial performance indicators is already used on some drilling contracts, to incentivize performance from drilling contractors and also to cover excessive low performance. Up to 5% of contract value can be adjusted thanks to these KPIs. The extensive use of well data improves the quality of reporting information from the field. It provides also a structured repository of all data recorded from the well operations. This digitalization process opens a world of capabilities for the operators in terms of predictive modelling and operations automation.
The calculation of the technical limit and the implementation of the lessons learned that can emerge from the analysis allows to increase the performance on the overall drilling phase through the reduction of the Invisible Lost Time. ILT are usually around 25% of all the drilling operations. This increase of performance has been measured on a series of drilling campaigns in a range from 6% to 8% time saving.
The calculation of impartial performance indicators is already used on some drilling contracts, to incentivize performance from drilling contractors and also to cover excessive low performance. Up to 5% of contract value can be adjusted thanks to these KPIs.
The extensive use of well data improves the quality of reporting information from the field. It provides also a structured repository of all data recorded from the well operations. This digitalization process opens a world of capabilities for the operators in terms of predictive modelling and operations automation.
The novelty of this approach is the combination of multiple data sources that provide unmatched analytics. In fact, these data are usually analysed on individual basis and limited to control in real time drilling operations. Therefore, the approach is creating value out of existing data, with limited resources.