Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
completion
Abstract This paper describes the joint and successful experience of Yinson and Baker Hughes on the Helang project, where 2 turbo-compressor units based on NovaLT16 gas turbine and 2BCL408/A centrifugal compressor technology for a gas export service have been installed on a FPSO (Floating Production Storage and Offloading) operating offshore Malaysian coasts. The solution’s definition started in 2017 and after 19 months of project execution the FPSO started its operations safely and on plan in December 2019. This was the first NovaLT16 installation on a floating unit. NovaLT16 draws on Baker Hughes latest innovations in gas turbine technologies bringing to the industry a gas turbine family that, thanks to a compact package solution, is particularly suited for Offshore floating environments. Considering the tight qualification process, coupled with the challenges faced by Yinson in the overall project development, the smooth and continuous operation of the turbo-compressor units represents a perfect example of industry cooperation and contributed to consolidate the relation of trust between the two Companies. This is particularly true in the case of Helang where risks and challenges were present: - During solution definition and design phase Pre-Assembled Unit (PAU) configuration for turbo-compressors was chosen to secure Yinson’s fast track execution schedule. - Before shipment full-power performance test was carried out at Baker Hughes facility (Massa, Italy) using 100% job equipment to de-risk site activities (moving potential troubleshooting before shipment of Baker Hughes supply). Additionally, extensive in-house checks/tests (Mechanical completion, loop checks, Unit Control Panel) were performed on auxiliaries to ensure track and completion of the delivery before shipping to China yard for integration and auxiliaries’ commissioning. - During shipyard construction phase, dealing with preservation & storage difficulties, jointly fixed & improved by Yinson and Baker Hughes. - During commissioning at FPSO, FPSO initial operation, speeding up issues resolution. - Jointly learning and improving, lessons learned sharing & implementation. - Adopting Remote Monitoring & Diagnostic in proactive approach to improve plant productivity and fast troubleshooting with dedicated algorithms.
Abstract Methane, a potent greenhouse gas is routinely or accidentally emitted during various phases of the oil and gas production lifecycle. As it is a powerful greenhouse gas as well as the major component of natural gas it has widespread effect on global climate change and energy security. While methane emission rules are being revised globally, the industry already has commercially available mitigating solutions that we will cover in this paper - a technology that is capable of permanently and eternally shutting off gas migration in single or multi casing annuli by forming a V0 gas tight seal. The source of emissions can be various, some from well operating and maintenance activities, others from well mechanic and integrity conditions that cannot always be resolved by traditional technologies or methodologies such as cement, resin, or elastomers. Bismuth alloy based sealing technologies have a wide range of applications during the well lifecycle – from well construction to well interventions and repair, production enhancement and well abandoning. These technologies not only support in extending the economic life of a well but also to permanently solve downhole flow or leak issues. This unique and field proven performance barrier technology alloys operators to solve unwanted downhole flow issues once and for all. Among various applications this paper will cover the most relevant cases related to mitigating methane emissions. Case 1: An operator having a well with a leaking production packer. Case 2: Abandoned and plugged wells losing integrity with time.
Abstract The Oil & Gas industry is rapidly evolving towards extreme digitalization. Simulations and digital twins are revolutionizing the way we think about the development and deployment of projects, products and services. Indeed, a digital twin is a virtual representation of a real-world physical system or product serving as the indistinguishable digital counterpart for practical purposes, such as system simulation, integration, testing, monitoring, and maintenance. Digital twins are commonly divided into different types. For the purposes of this study, we will refer to “plant” 3D digital twin, which is intended as the digital copy of a plant or worksite, and used for training, construction, maintenance, HAZOPS, and similar purposes. In this paper we present a new methodology combining digital twins and remote learning to improve personnel engagement on site induction training and to speed up well site access process in the Oil & Gas industry. We have designed and realized several well pad areas digital twins of existing Company O&G land rig sites located in Basilicata (Italy) to be used for safety induction and training of personnel and visitors prior to their access to site. The availability of the simulator on a web-based platform, accessible to personnel and visitors via authentication (login/password) from any location with an Internet connection, allows the Company to improve the induction process, avoiding time-consuming briefings at the time of site access. The induction process attended via the web-based immersive training simulator allows trainees to virtually walk-through a 3D reproduction of the Drilling & Workover sites. This builds confidence with a realistic scenario of the well pad area and the equipment used, as well as a complete understanding of the mechanisms involved, of the alarm procedures in case of emergency and of all related risks. The simulator also gives the Company the possibility to monitor the whole training process from its beginning to its completion, and to evaluate the trainees’ final acquired competences.
Multizone Open Hole Gravel Pack Completion with Selective Production Capability in ACG Field – Azerbaijan
Susilo, Yoliandri (BP, Sunbury, UK) | Dharmadhikari, Khsitij (BP, Baku, Azerbaijan) | Taha, Sherif (BP, Baku, Azerbaijan) | Ismayilova, Ayisha (BP, Baku, Azerbaijan) | Guliyev, Ilkin (BP, Baku, Azerbaijan) | Jafarli, Zaur (BP, Baku, Azerbaijan) | Kerimov, Natig (BP, Baku, Azerbaijan) | Kerimova, Ravana (BP, Baku, Azerbaijan) | Mammadov, Elvin (BP, Baku, Azerbaijan) | Veliyev, Samir (BP, Baku, Azerbaijan) | Wallace, Alex (BP, Baku, Azerbaijan) | Whaley, Kevin (BP, Houston, USA) | Foster, Mike (BP, Houston, USA)
Abstract Azeri-Chirag-Gunashli (ACG) is a giant field located in the Azerbaijan sector of the Caspian Sea. The major reservoir zones are multi layers sandstone formations and weakly consolidated where Open Hole Gravel Pack (OHGP) completions have become the standard design for production wells. To date more than 170 high rate OHGPs have been completed that are producing comingled from multi-layered sandstone formation. As the field matures, problems such as premature water and gas breakthrough are becoming increasingly common requiring the completion system to be inherently flexible to address such issues. The Multi Zone OHGP concept design has been developed to manage this increasing reservoir management complexity. Zonal isolation and selective production capability are achieved by installing combination of multiple Screen PBR and/or open hole packer in combination with seals unit and mechanical sliding sleeve in the inner string at the intermediate completion, and Inflow Control Valve (ICV) at the upper completion. To date, two Multizone OHGP wells have been completed successfully. The Screen PBR system has proved to provide effective zonal isolation or baffling. This system allows flexibility to deal with unexpected reservoir surprise (wet/gas zone) that requires zonal isolation on day-1 without major changes in completion design, thus reducing rig time & operational cost. This paper discusses design, execution, and result of the first two Multizone OHGP completions installed in the ACG Field. Installing multiple Screen PBR to provide baffling against crossflow is a novel concept. This technique does not compromise gravel pack quality or sand control integrity. The success seen with this technique makes a compelling case to further develop the concept on a larger scale in ACG and maximize field recovery.
- Asia > Azerbaijan > Caspian Sea > Apsheron-Pribalkhan Ridge > South Caspian Basin > Azeri-Chirag-Guneshli Field > Azeri Field (0.99)
- Asia > Azerbaijan > Caspian Sea > Apsheron-Pribalkhan Ridge > South Caspian Basin > Azeri-Chirag-Guneshli Field > Guneshli Field > Sabunchi Formation (0.93)
- Asia > Azerbaijan > Caspian Sea > Apsheron-Pribalkhan Ridge > South Caspian Basin > Azeri-Chirag-Guneshli Field > Guneshli Field > Podkirmaku (PK) Formation (0.93)
- (5 more...)
Surveillance, Analysis, and Optimization (SA&O) During Active Drilling Campaign
Zhang, Yanfen (Chevron U.S.A. Inc., Covington, LA, U.S.A.) | Bovet, Paul (Chevron U.S.A. Inc., Covington, LA, U.S.A.) | Samano, Lorelea (Chevron U.S.A. Inc., Houston, TX, U.S.A.) | Isabu, Ozzy (Chevron U.S.A. Inc., Covington, LA, U.S.A.) | Chima, Andres (Chevron U.S.A. Inc., Covington, LA, U.S.A.) | Everson, Erik (Chevron U.S.A. Inc., Covington, LA, U.S.A.) | Sun, Kai (Chevron U.S.A. Inc., Houston, TX, U.S.A.)
Abstract Deepwater drilling is an expensive complex operation. Real-time surveillance data and analysis for drilling operations are very important for ensuring safety and cost control. Due to the high production rate and high expense of deepwater wells, there are usually not many wells planned for developing a deepwater field. Therefore, the results of each well hold particular significance as additional reservoir surveillance data and are crucial for optimizing field development and production forecasts. The subject field of this paper is WRB (pseudonym) which is a deepwater field located in the Gulf of Mexico. In the past few years, about one to two new wells per year came online at WRB field. Thus, there has been a constant stream of surveillance data from both drilling new wells and production/injection at existing wells. All the surveillance data were processed and utilized for updating the reservoir simulation model that ultimately serves as the engine for optimizing the future well locations. This paper is intended to review and share the key learnings and best practices of Surveillance, Analysis and Optimization (SA&O) during the active drilling campaign of WRB field. A comprehensive effort was undertaken to review the historic surveillance activities carried out during drilling and post-drill, and to review the consequent value-adding decisions from effective use of surveillance information.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.46)
- Asia > Middle East > Kuwait (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (4 more...)
Abstract For the optimization of hydrocarbon recovery, tight and moderately tight gas reservoirs generally require hydraulic fracturing to connect the reservoir with the well and ascertain long-term sustained production. The open hole multistage fracturing completions (OHMSF) technology has become a game-changer to enhance production and optimize fracture placement. The open-hole sections allow the entire reservoir section to stay in contact with the wellbore at all times, while different segments of the completion assembly are equipped with isolation packers and fracturing ports and nozzles through which independent hydraulic fractures are initiated in stages and propagated in the reservoir. Throughout the years, OHMSF completion assemblies have gone through important upgrades and customization as functions of reservoir properties and well trajectories, and have proven to be one of the most cost-effective, efficient, and result-oriented technologies applied in the oil and gas industry.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.46)
Abstract Proppant flowback during the post-stimulation well clean up and production is a common occurrence in most hydraulically fractured wells. Whilst some proppant is expected to be produced during the well cleanup operations that typically follow the treatment execution, the long-term production of proppant can be problematic from an economic viewpoint. A thorough analysis of early time production data can be used to develop guidelines that can aid in minimizing the proppant flowback and associated issues. It is a well-known fact that the production of the proppant from a propped fracture is related to the forces acting on the proppant pack during the well that is actively producing fluids. Some of these, e.g., increase of effective stresses on the proppant, are stabilizing in nature, whereas others related to inertial flow from fluid velocity, viscosity and others can destabilize the pack. Most proppant flow back related studies associate the proppant production with critical flow velocities that are prevalent for given flowing conditions. This important parameter is thus a key to predicting proppant production during the well's producing life. In this study, flow rate and pressure data collected during the post-treatment flowback activity is used in simulating bottomhole (BH) production rates with the help of calculations. Using Gaussian solution scheme, the BH rate is distributed amongst the various perforation clusters while incorporating the effects of key hydraulic fracture characteristics in presence of simulated effective bottomhole flowing pressures across each fluid entry point into the wellbore. The solution is updated at each time step during the simulation. The production allocation is then used for calculation of effective flow velocities which are then compared with critical velocities to determine if proppant production can occur. Steps to mitigate or reduce the flowback, if present, are then recommended based on the analysis. In the flowback model developed during the study, flowing bottomhole pressures at each sleeve depth was generated with the help of hydrostatic and frictional pressures, and used in forward calculation of total flow rate at downhole conditions. The bottomhole flowrate was then allocated across various sleeves and finally, the associated production fluid velocities were calculated. These were compared with critical velocities corresponding to the fracture associated with each of the sleeves (or perforation set) to determine if there was potential of proppant flowback under the prevailing conditions. The procedure developed in the study can help in diagnosing conditions that may lead to proppant flowback and thus aid in preventing it by adjusting the controllable parameters during the treatment design and production phase. This technique can be easily implemented on similar completions worldwide.
Abstract Effective well completion design is crucial to optimize well and field performance, with many operators utilizing different techniques to achieve this important objective. However, the conventional means of designating wells for reservoir monitoring and standalone wells for production presents challenges to cost-effective reservoir management. Vertical observation wells are usually drilled in different locations to monitor the reservoir and assist with planning and intervention decisions by running periodic logs to obtain subsurface information. However, these wells can be costly and occupy valuable space that could be utilized for production. An alternate technique is to drill a pilot hole, perform all the necessary logging, and obtain the required reservoir information. The pilot hole is then plugged and sidetracked to a producer well. Nevertheless, the collected data only remains valid for a limited period due to potential changes to the reservoir. The demand for cost-effective, optimized drilling of production and observation wells has led to a paradigm shift in multilateral well technology that achieves both production and monitoring objectives for both laterals at the same time. Using this enhanced technology, wells can be completed with a pilot hole (vertical) drilled for reservoir evaluation throughout the life of the well, with permanent downhole gauges (PDHGs) installed for pressure and temperature monitoring, while the horizontal lateral functions as an oil and gas producer. Combining the observation and producer wells into one well results in cost savings and enhanced reservoir production and surveillance programs. In addition, the capability to access the lateral allows for intervention in both the motherbore and lateral at any time. Well intervention operations for a well completed with this multilateral technology involve slickline runs to gain access to the horizontal lateral, retrieve an isolation sleeve, and install a tubing exit whipstock (TEW) for lateral re-entry. Later, coiled tubing (CT) or wireline tractor can be run through the window into the lateral to perform the logging and intervention necessary. Upon completion, the TEW is retrieved from the window, the isolation sleeve is reinstalled, and the well is returned to production. Well intervention through such multilateral completion demonstrates the ease and efficiency of accessing both the vertical and horizontal lateral, without requiring a rig or completion retrieval. This paper will highlight the multilateral completion technology for accessing both laterals, which includes real-time monitoring capabilities that provide more reliable data for optimum well and field performance.
- Asia > Middle East (0.48)
- North America > United States > Texas (0.29)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion (1.00)
- Production and Well Operations (1.00)
Deployment of Novel Optimized Multizone Single-Trip Gravel-Pack System
Mogga, E. J. (SLB) | Ismail, A. (Brunei Shell Petroleum) | Adeyeba, A. (Brunei Shell Petroleum) | Sanni, I. (Brunei Shell Petroleum) | Kolakalapudi, M. (Brunei Shell Petroleum) | Lopez, M. (Brunei Shell Petroleum) | Lim, C. (Brunei Shell Petroleum) | Yun, M. (SLB) | Zou, C. (SLB) | Moses, N. (SLB) | Barretto, G (SLB) | Goh, K. (SLB) | Lim, Jia Yii (SLB) | Gil, J. (SLB) | Chua, D. (SLB) | Razali, R. (SLB) | Dada, O. (SLB)
Abstract Brunei Shell Petroleum (BSP) constructs many wells that require active sand control for multiple zones in cased hole environment with the option for zonal selectivity and allowing watered out zones to be isolated through well intervention. The most frequently used tubing in these wells is 3½-in. tubing which poses selectivity challenge when used in the standard 9⅝-in. multizone single-trip (MZST) gravel-pack system because the standard system uses 5½-in. modular screens and screen valves which are operated using 4.5-in. hard OD shifting tool which cannot be ran through the 3½-in. tubing. An innovative optimized MZST gravel-pack system alternative was developed and implemented successfully in Brunei and across the industry. This system offers: Higher accessibility and cost efficiency of MZST gravel-pack using conventional gravel-pack equipment. Selectivity option between zones during production Fluid loss control post gravel pack Improved rig time efficiencies Gravel-pack and Well Architecture Standardization The optimized system maintains critical zonal selectivity capabilities through use of standard screens and an internal string that features conventional sliding sleeve doors (SSD) connected through a three-way sub. This configuration simplifies installation, optimizes cost, and streamlines deployment. Additionally, the system design satisfies the unique well requirements of isolating, stimulating, producing oil and gas from the distinct zones in a single run, thereby enhancing overall well economics.
- Asia > Brunei (0.45)
- North America > United States (0.28)
Increased Oil and Reduced Water Production Using Cyclonic AICDs with Tracer Monitoring Applications in Peru’s Bretaña Norte Field
Acencios, L. (PetroTal Corporation, Lima, Peru) | Garcia, W. (PetroTal Corporation, Lima, Peru) | Huaranga, L. (PetroTal Corporation, Lima, Peru) | Guerrero, X. (SLB, Bogotá, Cundinamarca, Colombia) | Camelo, S. (SLB, Bogotá, Cundinamarca, Colombia) | Gurses, S. (SLB, Houston, Texas, United States) | Williams, B. (RESMAN, Houston, Texas, United States)
Abstract This paper presents the successful application of cyclonic autonomous inflow control devices (AICDs) for water management and the use of chemical tracers for monitoring and controlling the productivity of the different units to increase oil recovery in Peru’s Bretaña Norte Field by shuting down or choking units producing monstly water. The reservoir comprises an unconsolidated sandstone formation with an active aquifer and contains heavy oil with 23-cp viscosity downhole. The field’s location presents environmental and operational challenges, and the development plan seeks to use the latest technology to achieve production goals while minimizing the environmental impact. AICDs were identified as a technology solution to improve oil recovery. Unique chemical tracers were embedded in the sand screens to measure the oil and water production from each compartment without the need for well intervention. An integrated approach and technology workflow were used for a candidate well and included well placement using logging while drilling, predesign of AICD completions using advanced well modeling, tracer installation in the standard sand screen, and post-installation analysis of tracer samples to determine the flow contributions from each compartment and AICD performance along the wellbore. An optimized lower-completion strategy was essential to the planning and execution of the candidate well, which had challenging environmental constraints. The completion design was adjusted to obtain the estimated optimal inflow by identifying the number of compartments and AICDs required in each one along the 1,000-m-long horizontal well section. Incorporating the tracers as part of the permanent installation eliminated the potential need for an intervention and enabled the quantification of each compartment’s contribution during the cleanup and production phases. Tracer samples indicated a good cleanup, and the initial well performance was observed to have no water production. A few months after the cleanup was performed, water breakthrough occurred, and tracer analysis was used to identify the first compartments in which it occurred, helping the operator identify vertical heterogeneities at a structural level. Following 1 year of production and monitoring, oil recovery increased by 100% for this well compared to that of offset wells (from 15 to approximately 30%). Water production decreased by almost 2 million bbl per year, which represents a 50% decrease in the energy required to produce and treat water. The successful application of cyclonic AICDs with chemical tracers for monitoring in Bretaña Norte Field demonstrates that the oil production and recovery factor of heavy-oil fields with a strong waterdrive can be improved. This case study, which provides the results of 1 year of production, can serve as guidance for similar fields throughout Latin America. The resulting energy savings represent an important milestone in terms of reducing carbon dioxide (CO2) emissions and overcoming environmental challenges.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.74)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Sedimentary Geology > Depositional Environment (0.46)
- South America > Peru > Marañón Basin > Vivian Formation (0.99)
- North America > United States > Wyoming > Pedro Field (0.93)
- Asia > Middle East > Israel > Central District > Southern Levant Basin > David Field (0.93)