Temizel, Cenk (Aera Energy) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (Istanbul Technical University) | Putra, Dike (Rafflesia Energy) | Asena, Ahmet (Turkish Petroleum Corp.) | Ranjith, Rahul (Far Technologies) | Jongkittinarukorn, Kittiphong (Chulalongkorn University)
Smart field technologies offer outstanding capabilities that increase the efficiency of the oil and gas fields by means of saving time and energy as far as the technologies employed and workforce concerned given that the technology applied is economic for the field of concern. Despite significant acceptance of smart field concept in the industry, there is still ambiguity not only on the incremental benefits but also the criteria and conditions of applicability technical and economic-wise. This study outlines the past, present and the dynamics of the smart oilfield concept, the techniques and methods it bears and employs, technical challenges in the application while addressing the concerns of the oil and gas industry professionals on the use of such technologies in a comprehensive way.
History of smart/intelligent oilfield development, types of technologies used currently in it and those imbibed from other industries are comprehensively reviewed in this paper. In addition, this review takes into account the robustness, applicability and incremental benefits these technologie bring to different types of oilfields under current economic conditions. Real field applications are illustrated with applications in different parts of the world with challenges, advantages and drawbacks discussed and summarized that lead to conclusions on the criteria of application of smart field technologies in an individual field.
Intelligent or Smart field concept has proven itself as a promising area and found vast amount of application in oil and gas fields throughout the world. The key in smart oilfield applications is the suitability of an individual case for such technology in terms of technical and economic aspects. This study outlines the key criteria in the success of smart oilfield applications in a given field that will serve for the future decisions as a comprehensive and collective review of all the aspects of the employed techniques and their usability in specific cases.
Even though there are publications on certain examples of smart oilfield technologies, a comprehensive review that not only outlines all the key elements in one study but also deducts lessons from the real field applications that will shed light on the utilization of the methods in the future applications has been missing, this study will fill this gap.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
Introduction Of the three permafrost regions, our calculations show Mohe Basin has the thickest hydrate stability (1300 m). This is followed by Qinghai-Tibet Plateau (1200 m) and Qilian Mountain (800 m).
Carbon intensity (CI) of oil and gas production varies widely across global oil plays. Life cycle extraction from certain unconventional plays (
We perform well-to-refinery calculations of CI for major unconventional oil plays in North America and conventional plays in Asia Pacific. This approach accounts for emissions from exploration, drilling, production, processing, and transportation. The analysis tool is an open-source engineering-based model called Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions accounting using up to 50 parameters for each modeled field. This model was developed at Stanford University. Data sources include government sources, technical papers, satellite observations, and commercial databases.
Applied globally, OPGEE estimates show highest values in areas with extensive flaring of natural gas and very heavy crude oils - heavy oils require large energy inputs (
Unconventional production, especially from light tight oil is the most significant new source of fossil fuels in the last decade. Under a wide variety of carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments, and regulators need to be able to avoid "locking in" development of suboptimal resources and instead provide incentives for shale operators to manage resources sustainably. This approach provides quantitative measures of such actions. Oil producers must prepare by eliminating development of marginal projects, elimination of flaring and venting, optimizing hydraulic fracture treatments, using improved recovery methods (
Carr, Timothy (West Virginia University) | Ghahfarokhi, Payam Kavousi (West Virginia University) | Carney, BJ (Northeast Natural Energy, LLC) | Hewit, Jay (Northeast Natural Energy, LLC) | Vagnetti, Robert (National Energy Technology Laboratory, US Department of Energy)
Distributed temperature sensing (DTS) was used to record temperature from early 2016 to present for a Marcellus Shale horizontal dry gas well, MIP-3H, located in Monongalia County, West Virginia. In addition, after wellbore clean-out with water and nitrogen a flow scanner production log was conveyed on March 02, 2017. The flow scanner provides one day of gas and water production from each of the 28 stages in MIP-3H and from each of the clusters. The DTS data provides an opportunity to inspect the reservoir for Joule-Thompson (JT) effect, a phenomenon that describes cooling of an non-ideal gas as it expands from high pressure to low pressure, and obtain a relative production attribute along the lateral of the MIP-3H. The original fiber-optic DTS data shows the temperature along the lateral; however, due to the geometry of the well with toe up and the presence of a small fault and minor water production at Stage 10 relative gas production of each stage cannot be directly determined from the raw DTS data. We present two methods to generate DTS attributes that can be used to better reveal relative gas and water production through time from each perforation cluster and each stage of the MIP-3H. The first attribute deals with the deviations of the DTS measurements from the calculated geothermal temperature, while the second attribute calculated the difference between DTS temperature and the average daily DTS temperature along the lateral of the MIP-3H. We show that the latter DTS attribute provides a more robust image of temperature variations regime along the lateral than the former attribute. Negative values of the DTS attributes reveals JT cooling, resulting from stages of the MIP-3H with higher natural gas production. A correlation analysis of the production log with the calculated DTS attributes suggests that the production log is not representative of the entire production life of MIP-3H well. Temporal correlation with the DTS attributes is highest close to the production log recording day (March 2, 2017) decrease rapidly and the weak correlation switches from positive to negative.
Brunei offshore platforms are home to hundreds of maturing wells in need of ongoing interventions. Offshore operations in Brunei face several obstacles, (i.e., weather conditions, ageing platform facilities, limited lifting capability, and limited workspace), as well as tight work schedules that make the work challenging.
As with other mature fields, the Brunei wells need high efficiency operations to reach production targets. These challenges can be addressed with a purpose built compact semi-submersible vessel (CSS) with dynamic positioning (DP 2) equipped with a full catenary coiled tubing unit, a pumping unit with flowback capability, and a dedicated slickline unit.
Dual hull design with a compensated gangway increases the weather working envelope of the vessel. The coiled tubing catenary system with a reel turntable helps enable coiled tubing unit flexibility during rigup and work under varying weather conditions. Integration of the vessel and the coiled tubing unit helps enable a 24/7, 365 day work unit.
Average downtime caused by weather decreased by up to 10%, averaging 8.5% in 2 years, compared to previous work vessels with an average between 15 and 18% downtime because of weather.
Further efficiency improvement is gained through use of fit for purpose equipment. A 35 ton jacking frame helps enable injector and pressure control equipment stack up to be made up, function, and pressure tested offline. A small footprint flowback package was introduced that reduced the total number of lifts from 12 to 6, saving two hours lifting time per rig up/down. Overall rigging up time was reduced by approximately 20% with the improvements to equipment setup.
The reduced equipment necessary on the platform enabled wireline and coiled tubing to operate concurrently. This enables 24 hour wireline interventions to be executed offline more efficiently. Time savings for intervention completion were approximately 62%. This setup enables more efficient use of existing resources to complete the work scope.
The setup, collaboration, and execution on the vessel demonstrate the opportunity for improvement, which is important under current industry conditions, and help enable a cost effective yet robust operation.
Fu, Haifeng (Petrochina Research Insitute of Petroleum Exploration and Developement) | Yan, Yuzhong (Petrochina Research Insitute of Petroleum Exploration and Developement) | Xu, Yun (Petrochina Research Insitute of Petroleum Exploration and Developement) | Liang, Tiancheng (Petrochina Research Insitute of Petroleum Exploration and Developement) | Liu, Yunzhi (Petrochina Research Insitute of Petroleum Exploration and Developement) | Guan, Baoshan (Petrochina Research Insitute of Petroleum Exploration and Developement) | Wang, Xin (Petrochina Research Insitute of Petroleum Exploration and Developement) | Weng, Dingwei (Petrochina Research Insitute of Petroleum Exploration and Developement) | Feng, Jueyong (Tarim Oilfield Company)
ABSTRACT: Although a new technology of fiber diversion was introduced to hydraulic fracturing for ultra-deep sandstone formation, the operation is not always effective. This paper focused on the fracture reorientation mechanism and the relationship between injection pressure and fracture diversion according to large-scale physical simulation for fiber diversion in lab. The test results show that: firstly, the volume of fiber-based fluid is an important factor affecting fracturing diversion. If less fluid is designed, it would block original fractures inadequately. On the other hand, more fiber will result in sealing the open hole completely and fail to generate fracture diversion. Secondly, fracture initiation pressure after fiber frac fluid pumping can be used to evaluate diversion effectiveness. Higher level means lager reorientation angle. In the two-stage perforation, two fractures are initiated at different perforated wellbore depths. This validates the technology of fiber fracturing to create a better vertical coverage in the thick layer without mechanical packer. What we can learn from test results will help guide fiber diversion designing and evaluate corresponding fracture network in ultra-deep reservoir where great production contributed to natural fracture system, for example Dabei and Keshen gas fields in the Tarim Basin located in Western China.
There are amounts of natural gas reserve in ultra-deep (more than 6000m) sandstone reservoir in Western China, especially in Tarim Basin. However, due to some extreme geological conditions, great challenges exist in hydraulic fracturing to develop this kind of reservoir successfully[2-6]. Firstly, the traditional fracturing tools, such as fracturing packer and sliding sleeve, maybe not work effectively under the environment with high pressure(between15000psi and 20000psi), high temperature (between160° and 170°). Secondly, although the effective layer is very thick(between 100m and 300m), the internal vertical heterogeneity is very serious. So it is hard to create a better vertical coverage in the formation with fracturing. Thirdly, the natural fracture distribution is very complex due to active tectonic stress in this area. It is a favorable factor contributing to the improvement of reservoir permeability and gas production.On the other hand, it is also the main factor of the sand screen out which results in stimulation treatment failure. So fracturing technology for communicating with more natural fractures would be optimized to improve stimulated reservoir volume(SRV).
Khair, Abul (PETRONAS Research Sdn Bhd) | Zakaria, H. (PETRONAS Research Sdn Bhd) | Ali, A. (PETRONAS Research Sdn Bhd) | R., Y. Som (PETRONAS Research Sdn Bhd) | Hady, H. (PETRONAS Research Sdn Bhd) | Baharuddin, S. (PETRONAS Research Sdn Bhd) | Goodman, A. (PETRONAS Research Sdn Bhd)
Big attention was directed towards the deepwater fields offshore Sabah area after the discovery of commercial hydrocarbons Sabah in 2002. Hundreds of wells were drilled in up-faulted structural traps within North East trending thrust ridges which some of it are dry. The interpretation of these reservoirs was established as a series of four turbidite fans from Upper Miocene to Pleistocene. Yet, no correlation was found between the same fan in different locations with regards to geometry, thickness and mineral composition. This research studied over 50,000 sqkm of 3D seismic surveys, over 100 wells with different sets of logs including image logs, cores from two wells and bathymetric images. Normal seismic structural interpretation was conducted and seismic attribute of the turbidite fans were analysed. Seabed morphology was examined using bathymetry surveys and 3D seismic. The deepwater sediments type and depositional environment were investigated using core and log data.
The geometry of the oil prone sand reservoir bodies and heterolithic sand bodies within the deepwater fields was found to be of three types: North East trending narrow sand channels and turbiditic channel levees in the Southwest area of deepwater offshore Sabah, North East trending confined turbidite sand bodies bounded by elevated structural ridges south and south east of type 1, Deepwater fan system composed of channel sand, levee turbidites and local and regional MTD to the North East of type 1
North East trending narrow sand channels and turbiditic channel levees in the Southwest area of deepwater offshore Sabah,
North East trending confined turbidite sand bodies bounded by elevated structural ridges south and south east of type 1,
Deepwater fan system composed of channel sand, levee turbidites and local and regional MTD to the North East of type 1
This new understanding of the source and sediment supply of the deepwater fields Northwest (NW) Sabah explains the geometry, distribution and lack of correlation within the Miocene sediments. Thus, this study will direct the future exploration in the deepwater reservoirs.
Optimum mud window prediction is very crucial for drilling any well. Accurate prediction of pore pressure, fracture pressure and other geomechanical parameters such as stresses, rock mechanical properties and finally the collapse pressure are key for designing the optimum mud window and effective well planning. Predrill predictions of pore pressure and wellbore stability become more and more challenging as the industry is moving to more and deeper and ultra-deep water wells. This is primarily becaue of lack of offset calibration together with inherent probrems and challenges associated with deep water environments. A substantial amount of nonproductive time (NPT) was associated during the initial phases of drilling campaigns in the Brunei deepwater. Accurate mud weight window prediction using regional scale pore pressure prediction and geomechanical modeling clearly demonstrated a significant reduction in nonproductive times over the different phases of drilling campaigns till date. This also includes a regular update or refinement of the model as soon as new data or information becomes available. This paper presents some of the methodologies employed during well planning and construction with refinement along the way, resulting in improvement on pore pressure and geomechanical model. Our intent is to document and share our experiences and lessons learnt in Brunei deepwater well so that design and execution workflow can be continuously improved thus the well can be delivered safely and costeffectively.