Field development strategies in unconventional shale reservoirs have increased in intensity over the last few decades. Completion design and well spacing have been key focus variables in the incremental design process. With this wide range of design and development strategies, assets across different basins might end up with wells from a variety of design generations. This could make type curve creation even more complicated as it does not account for impact of hydrocarbon drainage in an area by the older (parent) well on the newer (child) wells. The present paper tackles this issue by addressing type curve development by including date dependent spacing variables to account for the dynamism of field development strategies over the years.
The present paper analyzes the impact of well spacing on type curve development in an asset. Type curve generation is a critical component in evaluation and subsequent planning so de-risking this step is very valuable. A lot of the analysis done in recent years is by considering well spacing as a static variable. The present analysis looks at spacing as a dynamic variable instead to account for time-series based variations. The spacing in the estimation process is also a 3-D spacing algorithm which identifies multiple points along the lateral section of the wellbore for a true evaluation of pressure transient propagation.
The present analysis showed the impact of date dependent well spacing on type curve development. The underestimation of well spacing in well-developed acreages was brought to attention as spacing mean deviations of upto 0.7 Standard Deviation were found between current well speacing and date-dependent well spacing scenarios analyzed. These deviations led to the type curves having upto a 40% EUR differential between estimation processes, with PV10 differentials higher than 100% in some cases. While the degree of impact of time series well spacing varied across the assets evaluated, quantifying the risk in type curve development and subsequent EUR estimation were key conclusions from the analysis.
The present paper presents a novel approach in tackling type curve development for parent and child wells observed across different basins. The paper provides guidelines on creating highly accurate type curves and highlights errors that may arise due to high well density and inter-well interaction by conducting the analysis in the high well density Middle Bakken formation.
Indonesia’s oil reserves continue to decrease each year. The amount of oil produced is greater than the amount of new reserves discovered. To overcome this imbalance, various efforts have been made by the government in increasing oil lifting. In addition to exploration activities, other efforts that can be done to improve oil lifting are through Improved Oil Recovery (IOR).
Since the establishment of SKK Migas, a total of 431 oil and gas Field Development Plans (FDP) have already been approved by the Government of Indonesia (as of December 2017) and about 31 of them were already using IOR methods (water flood and steam flood). Along with the sharp decline rate in Indonesia, more IOR projects are needed to restrain the decline oil rate in Indonesia. To attract and help contractors so they are willing to do the IOR projects, the Government of Indonesia offer an incentives such as investment credit and/or interest of cost recovery so that the IOR projects can be developed more economically. Moreover, there are some tools which these contractors may use to improve the economical nature of their projects, such as DMO Holiday, Depreciation Acceleration, Shared First Tranche Petroleum, Split Changes, and many more.
The purpose of this paper, is to obtain the average Production Costs of IOR Projects in Indonesia, which divided into 3 different IOR areas (North Sumatera, South Sumatera, and Kalimantan) based on the 31 IOR FDP projects. The data of the 31 IOR Projects were collected and afterwards the Profitability Index and Development Cost were calculated and distributed to those aforementioned areas.
The result of this paper showed that the lowest average production cost was in North Sumatera by 10 US$ per barrels and the highest average production cost of IOR projects in Indonesia was in Kalimantan by 25 US$ per barrels which remain lower than the current oil price. Based on the obtained production cost above, it can be concluded that the Indonesian IOR Projects are economically acceptable and hopefully can attract more contractors to propose IOR Projects in Indonesia.
Desai, Sameer Faisal (Kuwait Oil Company) | Rane, Nitin M. (Kuwait Oil Company) | Al-Shammari, Baraa S. (Kuwait Oil Company) | Al-Sabea, Salem H. (Kuwait Oil Company) | Al-Naqi, Meqdad (Kuwait Oil Company)
Kuwait Oil Company initiatives for ushering in a new era of digital transformation of its assets to intelligently and optimally manage the Oil and Gas fields were successfully realized with the completion of three pilot projects entitled Kuwait Integrated Digital Fields (KwIDF). This paper discusses major achievements of the Digital Oilfield technology implemented in Burgan KwIDF project and provides an insight on the challenges in operating it.
The Burgan KwIDF pilot successfully transformed GC-1 production asset into a fully instrumented DOF comprising of digital instruments and infrastructure installed at well site and the production facility. Real-time production data is transmitted to a state of the art collaboration center that integrates data continuously with automated workflows for validation, modeling and tuning of well and facility models. Right time decision support information generated from smart visualization tools allow quick actions for production optimization, well and facility management in a collaborative work environment.
There is persistent value realization from KwIDF technology implemented in Burgan field. It has generated substantial cost savings with faster response time in restoring production and reduction in non-productive time. Driven by the digital environment asset production has sustained at target as production gain opportunities are capitalized and losses compensated quickly.
Over the period of time with experience in utilizing the DOF technology it has been observed that the technology sustainment is dependent on the technology providers to a large extent. The main components that require their continuous support are the digital instruments, proprietary software, hardware and related infrastructure. Technical expertise in each domain is necessary for ensuring continuous and smooth operations in the field, wellsite and collaboration centers. Development of an integrated team of domain experts is crucial for successfully managing the DOF operations. Change management initiatives for developing an in house user champion team is mandatory for ensuring sustainment. The important lessons learned and solutions are discussed in detail.
In 2016, Malaysia Petroleum Management (MPM), the regulatory body of PETRONAS launched a 3 year dedicated strategy to intensify the idle wells restoration and production enhancement activities in order to maximize profitability through efficiency and success rate improvement. The basis of this strategy is the risk-sharing integrated operations in which the industry embraced it in all major well intervention activities. As the drilling activities dropped drastically over the past few years, it was crucial that the well intervention activities are carried out with high efficiency and success rate to restore the production.
The strategy went through various development changes throughout the 3 year journey. As the well intervention scope covers a wide range of activities, the framework of this integrated risk sharing mechanism provided the flexibility that is required for the execution of the various scopes and meet specific value targets either profitability from production gain or cost saving from decommissioning and infill drilling. Each of the project carried unique Key Performance Indicators (KPIs) as the guiding principles to drive the efficiency improvement that was required. A unique process called Total Wells Management (TWM) was implemented as the overlaying guide to further improve the uncertainty of subsurface challenges, operation optimization and commercial risk exposure.
This paper outlines the overall post mortem analysis of the 22 projects that were executed under this integrated operations strategy between MPM, ten operators and five main service companies. This strategy, known to the industry as the Integrated Idle Wells Restoration (IIWR) program, has become the new norm on how well intervention and subsurface assessments are executed to yield the best results especially in late life fields. The risk sharing integrated framework have proven to be a win-win scenario for all involved parties. The scope was also extended to cover non production adding activities such as wells decommissioning, well startups and pre drilling zonal isolation. IIWR have also opened up the opportunities for many ‘first in Malaysia’ projects such as the first subsea hydraulic intervention, first subsea decommissioning and also the reinstatement of technologies such as coiled tubing catenary. The biggest impact from this 3 years strategy implementation can be seen from the Unit Enhancement Cost (UEC) improvement where the average UEC was reduced from 14 to 17 USD per barrel of oil to about 4 to 7 USD barrel of oil.
Although there were major challenges, the overall results have been very encouraging. This framework is also being replicated for drilling and completion activities as well. Specific to well intervention, this IIWR framework is currently being put through an enhancement process to further expand the landscape of well intervention activities without compromising safety, operational efficiency and business profitability.
Frac hits are a persistent phenomenon that operators face periodically during unconventional field development. With basin maturity and infill drilling, frac hits play a major role in dictating overall production from multiwell pads. This paper focuses on the causes of frac hits and their subsequent impact on well EURs with solution methods to minimize negative impacts resulting from frac hits.
A fully numerical model-based was built around a four-well pad in Mountrail County, N.D., by integrating high-tier data including 3D sonic logs, nuclear magnetic resonance imaging and downhole spectroscopy to build a mechanical earth model of the reservoir. The parent well(s) are history-matched and geomechanical properties recalculated to changes in in situ stresses from parent well production. Infill wells are evaluated for asymmetric frac propagation toward depleted wells, and EURs are estimated to compare with thosethat of the parent wells.
The initial well stimulation program and the volume of production from the parent well has a huge impact on the degree of fracture asymmetry in infill wells. This preferential propagation creates additional stimulated surface area between wells. If the parent well was understimulated in the first place, the infill wells in general result in a positive frac hit, and additional barrels of oil are produced from the parent well with little or no impact on the infill well. However, if the parent well has been on production for a long period the hydraulic fracturing treatment deposits a huge volume of fluid and proppant in already depleted areas, and the reservoir pressure is not sufficient to flush out the excess water. This causes the parent well to experience a surge in water cut and reduction in oil rate for an extended period. In addition, the infill well's initial production will not metch the parent well IPs, and EUR can reduce drastically. This paper will categorically illustrate the timing, spacing and stimulation recommendations to minimize or mitigate these impacts.
Quantifying frac hits requires a comprehensive multiwell approach incorporating geomechanics, fracturing and production. This paper showcases case studies from the Bakken, identifying fracture asymmetry and production forecast from multiple wells, carefully considering all the physics, rock and fluid interaction in the subsurface strata. This will be a valuable tool for the engineers and geologists in the oil and gas community to effectively plan future infill development programs in unconventional reservoirs.
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.
Sidek, Sulaiman (PETRONAS Carigali Sdn. Bhd.) | M Hatta, Siti Aishah (PETRONAS Carigali Sdn. Bhd.) | Goh Hui Lian, Kellen (PETRONAS Carigali Sdn. Bhd.) | Tan, Kok Liang (PETRONAS Carigali Sdn. Bhd.) | M Yusuf, M Hafizi (PETRONAS Carigali Sdn. Bhd.) | Tanf Ye Lin, Catherine (PETRONAS Carigali Sdn. Bhd.) | Mawardi, M Hizbullah (PETRONAS Carigali Sdn. Bhd.) | Hamzah, Haziqah (PETRONAS Carigali Sdn. Bhd.) | Masngot, Ainul Azuan (PETRONAS Carigali Sdn. Bhd.) | Jeffry, Suzanna Juyanty M (PETRONAS Carigali Sdn. Bhd.) | Riyanto, Latief (PETRONAS Carigali Sdn. Bhd.) | Samaile, Eddy (PETRONAS Carigali Sdn. Bhd.) | Ahmat Kamis, Azman (PETRONAS Carigali Sdn. Bhd.)
Flow assurance has been a big focus of oil and gas operation in ensuring the delivery of the targeted production. A few fields located offshore Malaysia have been experiencing solid deposition inside tubing and stable micro-emulsion from early stage of their life. Oil production from Field W begin in January 2003, unfortunately when the wells were first opened-up it was observed to produce viscous emulsion and the production decline rapidly. Multiple analyses and efforts, including chemical and mechanical treatments, conducted over the years with minimal success. The damaging mechanism was determined to be caused by rare High Molecular Weight Organic Deposit (HMWOD) that have caused a significant pressure drop in the tubing, which consequently restrict oil production and tested to only disperse at above 100°C. It was suspected that the organic deposit was a naturally-occurring component of the crude oil itself, separating from the bulk of the crude as a consequence of the fluids movement towards the wellbore and the consequent drop in fluid pressure.
This paper focuses on the step-by-step workflow developed to identify the solid deposition, laboratory testing, treatments conducted and the result of different chemical treatments in Field W. The ultimate effort was by developing an advanced eco-friendly nano-fluid to remediate the rare issue of HMWOD and high melting point deposit in the field. The nano-fluid pilot treatment was conducted in 2014 and successfully rejuvenate the well with total of 20,000bbl incremental oil volume. Early 2018, subsequent treatments were conducted that contributed substantial improvement to the field production and at lower total treatment cost. This advanced chemical using nano-fluid technology concept is deemed feasible and will be further replicated in other fields.
This paper is highly beneficial to operators, petroleum and flow assurance engineers experiencing flow assurance issue on organic scale such as microcrystalline wax, high molecular weight wax and stable emulsion in the crude production. This paper also promotes the use of nano-fluid technology as part of the solution to flow assurance issue in Oil and Gas industry.
Inter-well communication in unconventional reservoirs has received huge attention due to its significant effects on well production. Though it has long been a known side effect of hydraulic fracturing, well interference has become more prominent and frequent as the industry moves to larger completion designs with closer well spacing and infill drilling. Fracturing of infill wells ("child" wells) directly places the older adjacent producing wells ("parent" wells) at risk of suffering premature change in production behavior. Some wells may never fully recover and, in worst cases, permanently stop producing after taking severe frac hits.
This paper presents an automatic data-driven workflow developed to identify inter-well interference events and their impact on EUR (estimated ultimate recovery) based on changes in the well productivity trend. The innovative approach of the workflow is the ability to automatically analyze interference using the complete production history for all wells in a field, using routinely collected data and without introducing human bias in the derivation of the results, instead applying a consistent criteria. The final result is a comprehensive collection of all well interference events occurred in a field, which may be used as a training set for statistical and machine learning based models aiming at predicting such events.
First, the automatic identification of anomalies in the well behavior was developed and criteria set to label the interference events. Next, probabilistic simulations are run to forecast multiple scenarios to quantify the impact of a well interference event reported in terms of change in cumulative oil production. Finally, every event is analyzed in the overall context of field operations, in an attempt to present possible causes which may explain the change of production behavior.
Net present value (NPV) and voidage replacement ratio (VRR) are the key drivers to define an optimal reservoir development strategy that maximizes returns while maintaining reservoir health. In the subsurface context, maximizing NPV consists of optimizing the well locations. Voidage replacement ratio (VRR), which is defined as the ratio between the volume of injected fluid and the volume of produced fluid, measures the rate of change in reservoir energy. Conventionally, operators try to maintain a VRR close to one during the whole field life. Typically a single value of VRR is used as a metric to represent the whole reservoir. However, this approach does not capture the lateral variation in pressure seen in giant fields.
This paper focuses on a more suitable method for determining the VRR for each user-defined pressure region using reservoir simulation. This method is used to plan the location of future wells during the long term development plan and maximize NPV and recovery. Two scenarios of well location will be examined. The first scenario consists of optimizing well location using a single VRR metric for the whole field. The second scenario uses the VRR from each pressure region to decide on the optimum number of wells per region.
This latter approach is shown to give better results in planning well location for future field development and is consistent with the reservoir pressure distribution across the field.
Data-Driven subsurface modeling technology has been proven, for the past few years, to yield technical and commercial success in several oil fields worldwide. A data-driven model is constructed for the first time for an oil field onshore Abu Dhabi, and used for evaluation of a reservoir with substantial reserves and comprehensive development plan; for the purpose of predicting production rates, dynamic reservoir pressure and water saturation, improving reservoir understanding, supporting field development optimization and identifying optimum infill well locations. The objective is to provide the asset with a decision-support tool to make better field development planning and management.
The subject reservoir is a low permeability carbonate reservoir and characterized by lateral and vertical variations in its reservoir rocks and fluid properties. More than 8 years of Phase-I development and production/injection data and extensive amount of well tests and log data (SCAL, PVT, MDT) from more than 37 wells were used to construct the Data Driven Model for this asset.
This new modeling technology, (TDM), integrates reservoir engineering analytical techniques with Artificial Intelligence, Machine Learning & Data Mining in order to formulate an empirical and spatiotemporally calibrated full field model. In this work, it is leveraged with other conventional reservoir modeling and management tools such as streamline modeling, isobaric maps and flooding conformance.
Several analyses were performed using the full field data-driven model; complementing the existing conventional numerical model. The accomplishments of the data-driven reservoir model for this project included, but not limited to, comprehensive history matching (including blind validation) and then forecast of Oil rate, GOR, WC, reservoir pressure and water saturation, injection optimization, and choke size optimization. The results generated by the data-driven model proved to be quite eye-opening for the asset management; as the model was able to identify potential areas of improving field efficiency and cost reduction.
When combined with numerical techniques, the calibrated data-driven model assist to obtain a reliable short term forecast in a shorter time and help make quick decisions on day-to-day operational optimization aspects. The use of facts (all field measurements) instead of human biases, pre-conceived notions, and gross approximations distinguishes data-driven modeling from other existing modeling technologies. Its innovative combination of Artificial Intelligence and Machine Learning (the technologies that are transforming all industries in the 21st century) with reservoir engineering, reservoir modeling and reservoir management clearly demonstrates the potentials that these pattern recognition technologies offer to the upstream oil and gas industry for its realistic digital transformation.