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.
Al Jadi, Issa A. (Kuwait Oil Company) | Desai, Sameer Faisal (Kuwait Oil Company) | Al-Ghanim, Wafaa (Kuwait Oil Company) | Al-Wazzan, Roqaya M. (Kuwait Oil Company) | Al Sabea, Salem H. (Kuwait Oil Company) | Al Haddad, Saud M. (Kuwait Oil Company) | Franco, Francy Milena (Schlumberger) | Khor, Siew Hiang (Schlumberger) | Saxena, Aditya (Schlumberger) | Zhang, Qiong Michael (Schlumberger) | Hapsari, Hairuni Safri Tri (Schlumberger) | Elayaat, Ahmed A.Fouad. (Schlumberger) | Bodwadkar, Suhas V. (Schlumberger)
A proven and effective integrated asset modelling (IAM) approach has been adopted to bring multiple interdependent wells, pipelines networks, and process facilities models together into one single truly integrated asset model for the Greater Burgan Oilfield in Kuwait. The integrated wells-network facility models via the IAM platform also includes a water processing facility model which consists of 2 effluent water disposal plants; a crude oil export pipeline network and a water reinjection network model. This paper describes how a representative integrated asset model was developed for the Greater Burgan Oilfield through a model centric approach executed within an Integrated Operational Excellence (IOX) Program towards a Digital Transformation initiative by Kuwait Oil Company (KOC) South and East Kuwait (S&EK) Group together with Schlumberger. It also describes how this tool enables the asset teams to evaluate different operating scenarios to further enhance well performance and the overall asset productivity via rerouting well flow path to an appropriate header, identifying well workover opportunities, reevaluating artificial lift design, adding future wells (for field development) and comprehensive understanding of well integrity and flow assurance studies. The assessment was done not only at a gathering center (GC) level but also asset-wide level where the complete system constraints, interactions and back pressure effects between more than 2000 different wells were fully accounted. The simulated results such as pressure gradient, temperature gradient and erosional velocity ratio gradient across the production networks are presented on the GIS map for easy opportunity identification. The availability of this fully integrated asset model with up-to date calibrated wells and network models and process models enables KOC engineers to better understand current well performance and production potential, identify any possible bottlenecks imposed by the large complex surface network and process facilities of Greater Burgan Oilfield.
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.
Desai, Sameer Faisal (Kuwait Oil Company) | Al Jadi, Issa (Kuwait Oil Company) | Al-Ghanim, Wafaa (Kuwait Oil Company) | Al Sabea, Salem H. (Kuwait Oil Company) | Al-Haddad, Saud M. (Kuwait Oil Company) | Franco, Francy Milena (Schlumberger) | Khor, Siew Hiang (Schlumberger) | Bodwadkar, Suhas V. (Schlumberger) | Saxena, Aditya (Schlumberger) | Zhang, Qiong Michael (Schlumberger) | Hapsari, Hairuni Safri Tri (Schlumberger) | Morales, Fernando (Schlumberger) | Halabe, Vijaya (Schlumberger)
Several efforts have been made in the past for generating an Integrated Asset Model (IAM) for the Greater Burgan field in Kuwait with mixed results on sustained utilization and benefits. A new effective full field Integrated Asset Model has now been developed within an Integrated Operational Excellence (IOX) program towards Digital Transformation of the Greater Burgan field. A proven model centric approach has been adopted to bring multiple interdependent wells, pipelines networks, and process facilities models together into one single truly integrated asset model. The IAM platform also includes a water processing facility model which consists of 2 effluent water disposal plants, a crude oil export pipeline network and a water injection network model. Development of this integrated wells-network-facility-crude export-water processing facility-water injection network model incorporating the 14 gathering centers in the South and East Kuwait (SEK) asset focused on providing all the essential valuable inputs to business processes for better asset management, faster and more accurate decision-making and optimizing the hydrocarbon flow path all the way from the reservoir till the export point. The assessment was done at full field level where the complete system constraints, interactions and back pressure effects between more than 2000 different wells were fully accounted up to the crude processing facilities. The availability of this fully integrated asset model with up-todate calibrated wells and network models and process models enables Kuwait Oil Company (KOC) engineers to better understand current well performance and production potential, identify any possible bottlenecks imposed by the large complex surface network and process facilities of Greater Burgan Oilfield. The simulated results such as pressure gradient, temperature gradient and erosional velocity ratio gradient across the production networks are presented on the GIS map for easy opportunity identification.
Is your energy business ready to go global?
In today's market there are few companies that are able to strictly focus on domestic opportunities. Increased competition in saturated home markets offer stagnant returns and in order to achieve growth, a company must either innovate, explore opportunities in foreign markets or both. By internationalizing, a company can capture new market share and may achieve continuous business growth. To accomplish this however, a thorough examination of the barriers and key considerations is vital for companies who are considering taking their business to the international stage.
To begin, a company should find a market for their goods and services and then plan, test and evaluate their internationalization strategy. By reviewing different models, theories and tools meant to assist a company when entering into the global economy, these findings and concepts are then applied to a case study of an oil and gas mid-sized service company which internationalized into the South East Asian market.
The intent of the paper is to identify key external considerations that a small to mid-sized oilfield service company should be cognizant of prior to entering into a host market. For many businesses, the rewards far outweigh the risks when a company decides to internationalize. Ensuring they have a proper strategy will set the company up for success. Key global expansion considerations were validated during the initial phases of the internationalization process and after creating a roadmap for the case study oilfield service company as it expanded into South East Asia. Further, several recommendations were put forth. These included host regulatory environment risks, political stability and culture. The goal of this paper outlines how companies can follow their own path, rather than following a herd mentality to go global successfully.
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.
The objective of this paper is to explore the benefits of using the Interactive Epoch-Era Analysis (IEEA) methodology for evaluating architectural changes in a trade space exploration study. In this paper a subsea tieback offshore Brazil will be used as reference case to investigate this premise from a full field development perspective.
An automated concept exploration tool is employed. It applies meta-heuristics to generate different offshore facilities concepts with varying building blocks. The interaction between reservoir behavior and facilities design is accounted for, meaning pressure and temperature losses throughout the system are taken into account in each concept differently. These concepts are ranked in terms of economic performance indicators (NPV, IRR, etc.), and each run with a given set of boundary conditions covers what is called an Epoch. This process is iterated for the whole life of field with a set of different boundary conditions, such as commercial aspects ($/bbl, $/MMBtu, market demand) and/or technological maturity aspects (TRL, novel technological concepts), generating what is called an Era. The whole data set is then evaluated in an interactive platform thru the Humans-In-the-Loop (HIL) process.
Model Based Systems Engineering (MBSE) is being employed successfully in other engineering fields outside the O&G context such as the aerospace and automotive industries. While digital tools have been identified as a potential key contributor to the future of O&G performance enhancement and further cost reductions, that is yet to be shown. This work intends to provide backing for that argument in one of the potential applications during early concept exploration phases by showing that quick high value assessments following an MBSE approach may be carried out, once significant effort has been put into proper development, verification and validation (V&V) of such digital tools.
While integrated models for asset development have long been a subject of interest for O&G operators, the application of Systems Engineering concepts to it has not yet been thoroughly explored. Systems Engineering provides a rigorous and proven method of dealing with complex systems that is highly applicable to offshore field developments. MBSE is the current State of the Art for capital intensive projects such as space exploration spacecrafts and rovers. Learning from these successful use cases and applying these methodologies in the development of digital technologies may provide a new set of tools in the belt of O&G operators Facilities Engineers and alike. The study case presented shows MBSE’s capability of capturing intrinsic non-linearities and specificities of each O&G field/location while ensuring project wide functional requirements are successfully met.
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.