Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
The high-profile blowout at Macondo well in the US Gulf of Mexico, brought the challenges and the risks of drilling into high-pressure, high-temperature (HPHT) fields increasingly into focus. Technology, HSE, new standards, such as new API procedures, and educating the crew seem to be vital in developing HPHT resources. High-pressure high-temperature fields broadly exist in Gulf of Mexico, North Sea, South East Asia, Africa, China and Middle East. Almost a quarter of HPHT operations worldwide is expected to happen in American continent and the majority of that solely in North America. Oil major companies have identified key challenges in HPHT development and production, and service providers have offered insights regarding current or planned technologies to meet these challenges. Drilling into some shale plays such as Haynesville or deep formations and producing oil and gas at HPHT condition, have been crucially challenging. Therefore, companies are compelled to meet or exceed a vast array of environmental, health and safety standards.
This paper, as a simplified summary of the current status of HPHT global market, clarifies the existing technological gaps in the field of HPHT drilling, cementing and completion. It also contains the necessary knowledge that every engineer or geoscientist might need to know about high pressure high temperature wells. This study, not only reviews the reports from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) and important case studies of HPHT operations around the globe but also compiles the technical solutions to better maneuver in the HPHT market. Finally, the HPHT related priorities of National Energy Technology Laboratories (NETL), operated by the US Department of Energy (DOE), and DeepStar, as a strong mix of large and mid-size operators are investigated.
During drilling operations, downhole conditions may deteriorate and lead to unexpected situations that can result in significant delays. In most cases, warning signs of the deterioration can be observed in advance, and by taking proactive actions, drillers can avoid serious incidents such as packoffs or stuck pipes. A new analysis methodology, relying on an automatic real-time computer system, has been developed to detect those early indicator conditions. The methodology involves constantly computing the various physical forces acting inside the well (mechanical, hydraulic, and thermodynamic). These physical forces are coupled by an automatic model calibration, which then gives a reliable picture of the expected well behavior. Through analysis of the deviations between modeled and measured values, an estimation of the current state of the well is derived in real time. Changes in the well condition are an early warning of deteriorating well conditions. This paper precisely describes the real-time analysis and the results during some drilling operations. The software has been used for monitoring 15 unique wells located in five different North Sea fields. All major situations were signaled in advance at different event time scales: Rapidly changing downhole conditions (such as pulling a drillstring into a cuttings bed) were typically detected 30 minutes ahead of the actual event, medium-duration deteriorations were detected up to 6 hours before the incident, and slow-changing downhole conditions were signaled up to 1 day in advance. Several examples that illustrate the detected incidents over distinct time periods are described. The availability of good-quality real-time data streams makes it possible to implement such analysis tools in an integrated operation setup. Early symptom detection can be used to make decisions in a timely fashion, on the basis of quantitative performance indicators rather than subjective feelings and personal experience.
This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible pumps in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains approximately 1.3 billion barrels of STOIIP in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately 40% of the oil production is from the ESP oil wells.
To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields.
The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 100 deviated producers. ESP was selected as the artificial lift mode for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift mode for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 11 horizontal producers are on ESP lift and the remaining three wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities.
The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and SRB. 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field.
Accurate prediction of individual well potential and estimation of field capacity are the key for managing Coal Seam Gas (CSG) wells and its deliverability to Liquefied Natural Gas (LNG) plant. Because there are no downhole gauges in these wells there is limited reservoir data. The associated uncertainty, the absence of fast predictive wellbore models and challenges in generating accurate well performance predictions add to the deliverability challenge.
This paper presents a method used to estimate CSG well performance for Australian CSG assets using neural network (NN) and proxy modeling. Traditional methods for prediction of well potential, such as numerical simulation or statistical techniques, have significant limitations. Numerical prediction is traditionally accurate but very complex in setup and computation; statistical techniques have the advantage of being fast but often lack accuracy.
The approach starts with the automatic acquisition, validation, and quality control of static and dynamic production parameters in proxy modeling. Based on the relationship and similarity of key performance indicator (KPI) profiles, the wells are grouped into various clusters using a NN self-organizing map (SOM) technique. For each cluster group, a workflow is defined to estimate various well parameters used to predict individual well potential. A generic proxy model can be designed for each cluster for future prediction and capacity modeling. The workflow also allows tracking of capacity at different operating points on a daily basis for wells, group of wells, and fields and can be leveraged further by generating scenarios for various constraints on production parameters and facility controls. The entire workflow process can be standardized, scheduled to run automatically, and stored in a workflow library for secure deployment and sharing across the organization.
Australian CSG business
There are enormous resources of coal seam gas worldwide. In the last three years, there has been a considerable interest in the production of LNG from CSG as witnessed by the various projects now being developed in Queensland, Australia. Australia is known for its gas production and lately recognized as a leader in proving the commercialization of CSG production. Coal seam gas economic demonstrated resources (EDR) have doubled in the last three years and at the end of 2011 were 35 905 PJ (32.6 tcf). Total identified resources of CSG are estimated to be around 223 454 PJ (203 tcf), including sub-economic resources (SDR) estimated at 65 529 PJ (60 tcf) and inferred of 122 020 PJ (111 tcf) (Bradshaw, Hall, Copeland, & Hitchins, 2012). Up until recently, operations were relatively small and mainly focused on supplying the domestic market. Global growth and increases in energy demand from countries such as China, Japan and India are encouraging large oil and gas companies to expand into the CSG-based LNG business. Australia's geographical location is an added advantage to meeting the energy demand of these countries.
Sirat, Manhal (ADCO Producing Co. Inc.) | Al-Dayyani, Taha (Abu Dhabi Co. Onshore Oil Opn.) | Singh, Maniesh (ADCO Producing Co. Inc.) | Abdul Rehman, Abdul Samad (ADCO Producing Co. Inc.) | Al-Zaabi, Naema (Abu Dhabi Oil Co. Ltd.) | Mahmoud, Sabry Lotfy (Abu Dhabi Co. Onshore Oil Opn.) | Shuaib, Mohamed (Abu Dhabi Co. Onshore Oil Opn.) | Moge, Michel (Abu Dhabi Co. Onshore Oil Opn.)
The identification and characterization of fractures, and assessing their impact on flow behavior in reservoirs have been one of the key challenges in defining the field development strategy. The studied field is an onshore carbonate field situated in Abu Dhabi, U.A.E., with main reservoir lithofacies characterized, from top to the bottom, as foraminifera, skeletal wackstone representing c.65% of the reservoir, and mix of skeletal peloid wackstone-packstone and algal, skeletal floatstone-boundstone representing c.35% of the reservoir.
An integrated approach has been used to identify and characterize the natural fracture types and their distribution in this reservoir including core description, thin sections, borehole image (BHI) log interpretation, rock mechanical properties, well test and production data. A fracture conceptual model has been built emphasizing some of the most relevant fracture attributes such as fracture size, frequency and mechanical properties. These rock mechanical properties have been used to define the mechanical units in each well and to populate throughout the reservoir. Dynamic data, particularly well-test analysis have also been used in this study to verify the conceptual model and other findings.
We found that rock mechanical properties have been the key factors in controlling fractures in the reservoir, and that the distribution of these mechanical units can help predicting areas of high strain potential/ stressed fractures, hence help well placement and development planning. It has also been found that the diagenetic fractures (stylolite-related and vug-associated), predating the dominant tectonic-related fractures, were formed in the reservoir by unloading and exhumation mainly during the Simsima/ Cenomanian Time. From limited production data, we could conclude that the fracture to matrix permeability contrast is low.
Our methodology and results can be utilized in to other fractured carbonate reservoirs with similar tectonic/structural setting in the region for better understanding and optimize future field development.
Key words: tectonic fractures, diagenetic, integrated approach, carbonate reservoir, fractures modeling, Abu Dhabi
The Ichthys LNG Project
INPEX has begun construction of one of the world's largest oil and gas projects following the Final Investment Decision (FID) on the US $34 Billion Ichthys LNG Project in Australia on 13 January 2012. The Ichthys LNG Project is a joint venture between INPEX (Operator) and Total with Tokyo Gas, Osaka Gas, Chubu Electric and Toho Gas.
The Ichthys Field is situated in the Timor Sea approximately 200 kilometers off the Western Australian coast and over 800 kilometers from Darwin. Three exploratory wells drilled in 2000 and 2001 resulted in the discovery of an extremely promising gas and condensate field with resource estimates from two reservoirs totaling approximately 12TCF of gas and 500 million barrels of condensate. Conceptual studies, FEED and ITT followed and development leading to sanctioning of the Ichthys LNG Project by INPEX and Total.
Gas from the Ichthys Gas-Condensate Field in the Browse Basin will undergo preliminary processing offshore to remove water and extract condensate. The gas will then be exported to onshore processing facilities in Darwin via an 889 kilometer subsea Gas Export Pipeline (GEP). Most condensate will be sent to a Floating Production Storage and Offloading (FPSO) vessel for stabilization and storage prior to being shipped to global markets. The Ichthys LNG Project is expected to produce 8.4 million tons of LNG and 1.6 million tons of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.
Production from 20 subsea wells in the first phase - 50 will be drilled in total - will be sent to the Central Processing Facility via 8?? rigid lines connected to flexible risers. The flexibles will be supported by a 110 meter high jacket type riser support structure. You see, no aspect of the Ichthys LNG Project is small.
Effluents will be separated on the Central Processing Facility (CPF), a semi-submersible floater. Gas will be dried and compressed prior to being sent ashore via a GEP. Compression will be from four compressors, designed for 590.7 MMSCFD. Following initial treatment, most liquids will be transferred from the CPF to the nearby FPSO for processing and storage. The 330 meter-long FPSO will be a weather-vaning ship-shaped vessel that is permanently moored on a non-disconnectable turret. It has been designed with a storage capacity of nearly 1.2 million barrels. Loading of two offtake tankers in tandem will be possible from the FPSO.
The oil & gas industry is constantly adapting to change, be it related to price, technology or market demand. High prices of crude oil and advances in technology have allowed producers to access resources previously out of reach, and extract maximum value from these resources. With this, however, operational risk is significantly augmented - both upstream and downstream. In order to cope with this increased risk, it is vital that oil & gas companies have a process safety management (PSM) system that fully integrates management of change methodologies.
DuPont has developed a PSM system that fully integrates change management across multiple facilities, among personnel and in light of technological advancement. While these must be considered singularly, it is also important for companies to build a holistic system that accounts for the interdependent nature of operational systems, and thus address process safety from every possible angle - training and skill development to hazard analysis and maintenance. However, as only a limited number of procedures [PW1] can be universally applied to cope with changing process conditions, this paper will also detail the means through which companies can develop customized solutions for specific conditions and contexts.
By developing a model that can effectively manage change, it is possible for oil & gas companies to not only avoid catastrophic incidents, but also increase the overall safety of an operation, while concurrently maximizing efficiency, cost-effectiveness and quality.
The extraction and processing of oil and gas is a highly technical mechanical operation that involves volatile and corrosive substances in often extreme conditions. As such, it is vital for companies within the oil & gas sector to develop a holistic PSM system that can successfully manage process safety, while remaining agile enough to respond to specific issues, and any changes thereof.
Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.
A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.
Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.
This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.
The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
Sirat, Manhal (ADCO Producing Co. Inc.) | Koyi, Hemin (Uppsala University) | Popa, Desdemona Magdalena (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Mahmoud, Sabry Lotfy (Abu Dhabi Co. Onshore Oil Opn.)
A carbonate field in Onshore Abu Dhabi is characterized by its complicated structural setting, which involves basement tectonics. A new seismic attributes analysis has been conducted to reveal the structural style, and to identify significant lineaments representing possible major and minor faults. Based on this analysis, a conceptual model is presented, which reveals the development mechanism of the major structure and associated faults.
Structural constraints such as lineaments length, faults throw and displacements are strongly related to the seismic resolution constraint. Whereas timing of the structural development events represents a challenge and needs to be linked to sedimentation and sequence stratigraphic framework and thus needs further study.
In total, six fracture sets have been identified including the N75W, N45W, NS, EW, NE-SW and N70E. The Conceptual structural model shows that the contractional structure has been modified as a giant positive flower structure-like associated with a basement strike slip fault. At least two major longitudinal faults bound the structure parallel to its fold axis (NE-SW), which pose sigmoidal map geometry. There are numerous transverse faults linking and/or cross cutting those longitudinal faults creating andulations that may define new minor plays.
Significant implications of this study include better understanding of the regional structural geology of Abu Dhabi, and define new plays within the studied structure. In addition, the new identified fracture system provides essential information for the ongoing and future development plans for this field and for other fields in the region with similar structural settings.
Key words: Structural conceptual model, Carbonate hydrocarbon field, Abu Dhabi