In Kuwait, the traditional approach to Field Development has been to drill wells, whether Vertical or Horizontal, Single or Dual, with completions dedicated to either Production or Injection. However, as increasingly more wells are being drilled to develop the stacked reservoirs, surface infrastructure is growing in complexity with regard to Production Flowline routing, Gathering Facility location, Satellite Manifold placement, Water Injection distribution lines routing, and access road construction. Also, since the reservoir stack is a combination of areally extensive Carbonates overlying shale & channel sand sequences, optimum surface locations of Injectors for one reservoir is now increasingly conflicting with the optimum surface locations for the Producer of another reservoir.
The North Kuwait team presented options that could reduce the requirement for excessive wellbores for both new Producers and Injectors. One of which is the utilization of a single wellbore to both Produce Oil from one reservoir and Inject Water into another reservoir simultaneously. This novel approach utilized the most popular Dual Completion equipment, but rather than produce or inject concurrently from separate reservoirs or layers, production & injection are achieved simultaneously through either tubing string. Tubing movement calculations were made to ensure that the resultant axial tubing forces exerted by simultaneously injecting cold water and producing hot reservoir fluid would not cause the Dual packer to prematurely unset.
This unique completion has several advantages which include the production acceleration from an adjacent reservoir/layer that would have been postponed for the life of the Injector and the elimination of the drilling of a new producer to access the oil from an adjacent reservoir/layer to the target injection zone. Additionally, the elimination of the drilling of an Injector well if its optimum subsurface location is close to, or coincides with, an existing Producer from an adjacent layer, and the reduction in access road construction and location preparation costs. This strategy will significantly reduce Unit Development Costs while concurrently ramping up production levels. With simple conversion workovers, rather than drilling new wells, Oil Production potential that is presently unexploited in dedicated Injector wells can immediately be realized. Pressure support Injection can be initiated as soon as distribution injection lines are made available via similar conversion workovers.
Ahmadi is a shallow carbonate reservoir consisting of two units AA and AB. These units are thin, highly faulted and irregularly-fractured. The matrix permeability of Ahmadi is very low; it ranges between 0.01 and 10 md. However, the secondary permeability is playing a big part on achieving some remarkable production figures.
The reservoir is believed to have some fractures which have been proven from image logs. These make the simulation of the reservoir quite challenging. This paper describes how fractures were incorporated in the simulation of Ahmadi where three different methodologies have been considered. These are: single porosity with seismic attributes enhancement, dual porosity dual permeability (DPDP) and virtual fracture network modeling.
In the single porosity model, the fracture properties were represented along with the matrix properties in one cell. It was done by considering some seismic attributes such as Anttrack and Anisotropy and then using the Attributes distributions to generate permeability multipliers. For the Dual Porosity Dual Permeability model where the matrix and fracture cells are different, the seismic attributes were used again but to generate a stochastic fracture network. Alternatively, the virtual fracture network model was created by having fractures intersecting each well based on some assumptions related to well spacing, fracture aperture and fracture direction.
The listed methodologies are discussed in details in this paper. It was found that the virtual fracture network approach led to fast and robust history matching results. It was also observed that Anttrack and Anisotropy seismic attributes helped to represent the fault and non-fault related fractures in both single porosity and dual porosity dual permeability models.
Failure of umbilicals such as leakage or blockage in the hydraulic lines can be a challenge during operation of subsea infrastructures such as Christmas trees. These failures cause loss of redundancy and, in worst case, the operator will lose control of important valve functions on the trees. In that instance, the operator is forced to shut down production to perform costly umbilical repair or replacement prior to resuming operation.
As an alternative to umbilical repair and replacement, Siemens has developed a compact subsea hydraulic power unit (SHPU) for installation close to the subsea tree. The unit is intended as a standardized part of the operators’ toolbox, and is connected to the tree by Subsea Instrumentation Interface Standardization (SIIS) level 2 interfaces. The SHPU will take available electrical power from the existing infrastructure at the well site, and store it in a battery based energy bank. When hydraulic power is needed for valve operations on the well system, it will be provided by a pump driven by an electrical motor. Installation and retrieval of the SHPU can be done using a typical inspection, maintenance and repair (IMR) Vessel with a lift wire and remote operated vehicle (ROV) assistance.
The SHPU may also be used as a building block to develop long step-out developments in a cost-efficient way. By producing the hydraulic power locally at the seabed, it is possible to remove the hydraulic lines of the umbilical and thereby gain significant reductions in investments.
Within Oil and Gas service companies, there is tension between developing medium to long-term capability and delivering the service clients demand. Balancing these two requirements is a continual challenge. Both employers and employees recognise a constant need to develop their skills and knowledge base, and an important requirement of an employer is to be astutely aware of their organisation's talent requirements. Employers must identify and acquire talent through recruitment or retraining, and once acquired, employees must be trained and developed to meet the specific business demands for the present and the future. The need to ensure the effectiveness and application of the knowledge transfer process is more important than ever, and has to be done by measuring the skills and knowledge of the individual through a structured competence programme. There are practical challenges of embedding a competency process within an international organisation and these will be explored in this paper.
In the past, the oil and gas industry placed a high premium on experience, which is by definition a reflection of time served. The rapidly changing needs of clients necessitate the acceleration of learning and development activity in the workplace, as the supply of experienced individuals does not always meet the demand. Therefore employers are required to obtain talent and accelerate the knowledge and skills of existing employees, ensuring that talent has been converted into a capability that adds value to the organisation and fulfils client needs by ensuring delivery of excellent service quality. Traditional competency measurement of skill and knowledge has been paper-based, and whilst effective, has proven to be both labour and time intensive when performed by assessors. An alternative approach is electronic competence measurement deployed via a learning management system that allows for electronic knowledge and skills assessment, reducing administration burden and the need for assessor intervention through the automatic recording of completions. If not skillfully managed the binary nature of this approach can limit the integrity and robustness of the system so it is imperative to ensure that additional measures are introduced to maintain and indeed enhance the assurance of the individual's competency.
This paper will discuss the cultural, geographical and technological challenges encountered and how they were resolved during the development of a global competency-based system, in an international service company. The paper will propose a | number of innovative methods to address the issues encountered when incorporating a global electronic competency system, whilst maintaining its on-going integrity.
Khalifeh, Mahmoud (University of Stavanger) | Saasen, Arild (Det Norske Oljeselskap and University of Stavanger) | Vrålstad, Torbjørn (SINTEF) | Larsen, Helge B. (University of Stavanger) | Hodne, Helge (University of Stavanger)
When a well reaches the end of its life-cycle, it is permanently plugged and abandoned. Since the first discovery in 1966 on the Norwegian Continental Shelf (NCS) till October 2014 nearly 5496 wells have been drilled. Of these wells, 3978 are development and 1518 are exploration wells. Of the development wells, 699 have permanently been abandoned and 279 are in temporary abandonment status. It is estimated that 3279 development wells need to be plugged and abandoned in the future. Besides, the number of wells which will be drilled in future should be added for plug and abandonment.
The costs of these P&A operations will be substantial. Hence, there is a need for technology development that will reduce the costs of all these operations. This development involves both techniques, tools and materials. The current work describes different plugging materials and important characteristics of permanent barriers with respect to long-term integrity. In addition, different roots of failure modes of permanent barriers have been discussed. Geopolymers are suggested as possible permanent plugging materials. Geopolymers are aluminosilicate materials, which solidify. A new geopolymeric material is introduced for the permanent zonal isolation and well plugging; an aplite-based geopolymer. Its placeability was studied by investigating the rheological behavior of the geopolymer slurries. The Bingham and Casson models selected to simulate the slurries' viscosities. Both models were fitted to the measured data. Strength development of the produced geopolymers showed sufficient compressive strength. X-ray powder diffraction was used to characterize the microstructure of the produced geopolymers. X-ray patterns showed formation of an amorphous phase. The measured permeability was in the range of nano Darcy. The initial result shows that the aplite-based geopolymer has the potential to be utilized as a permanent plugging material for well plugging and zonal isolation.
Enhanced oil recovery (EOR) schemes have been slow to evolve in the exploitation of hydrocarbons from the UK Continental Shelf. They are generally much more expensive to execute offshore than in onshore USA where they are relatively common. This paper provides a detailed analysis of the economic aspects of several EOR projects namely low salinity waterflood, polymer flood, and miscible gas injection. Detailed economic modelling of example schemes finds that, in current circumstances in the UKCS, prospective returns, while worthwhile in undiscounted cash flow terms, are only very modest at discount rates reflecting the cost of capital. It is also noted that there are several significant investment risks. Further tax incentives relating to the purchase of polymer and miscible gas could enhance returns to these EOR projects without introducing any distortions.
The Development of Ice Ridge Keel Strengths is a four-year collaborative venture between the C–CORE Centre for Arctic Resource Development (CARD) and the National Research Council – Ocean, Coastal & River Engineering (NRC-OCRE). The main focus of the project is to investigate the failure mechanisms associated with gouging ice ridge keels and the conditions under which these keels will continue to gouge without failure. This is important for the design of subsea structures in shallow waters, where ice keels have been observed to scour the sea floor, posing a threat to pipelines and subsea infrastructure. A series of near full-scale keel-gouge tests were carried out to investigate the strength characteristics of a first-year ice keel and its subsequent failure as it was pushed into an artificial seabed. The ice keels were constructed using freshwater ice blocks with a nominal thickness of 10 cm, produced in a cold storage facility prior to the start of the test program. The ice keels were constructed with the aid of a keel former that produced idealized keel geometries of 1.7 m depth, 4 m length and 3.5 m width. Once constructed, the keels were lowered into the water and left overnight to consolidate with air temperatures held at -20°C. The keel samples were tested using a custom-built frame that was designed and used in the Pipeline Ice Risk Assessment and Mitigation (PIRAM) Joint Industry Project. The frame applied a vertical surcharge load to the top of the keel whilst a soil tray was displaced horizontally, causing the bottom of the ice keel to interact with an artificial seabed. A total of ten keel tests were conducted in this test program. The parameters varied were the initial temperature of the ice (-3° and -18°C), the initial surcharge pressure (5-60 kPa), the soil tray velocity (1-20 mm s-1) and the consolidation time (19-48 hrs). An overview of the test program and preliminary results are discussed.
There are many small scale onshore and offshore gas fields and there are also many diverse small LNG consumers around the world. However, smaller unit of gas fields could not be practically developed due to unfavorable unit price competition with larger ones. Therefore, many stranded gas fields are still waiting for new viable technology for the small unit production. In order to have unit production cost competitiveness, CAPEX and OPEX should be reduced. Cluster LNG technology based on increased pressure liquefaction has distinct advantages in OPEX and CAPEX with inherent high liquefaction efficiency together with superior environmental performance. One of the potential gas consumers for the small capacity LNG would be fuel oil fired diesel engine or gas turbine power plant operators who eagerly attempt to change the fuel source to natural gas due to high fuel oil price. Most of the cases, power plants are located far away from the gas fields, so efficient gas transportation solutions have to be provided. LNG is efficient means of gas transportation between 2 different locations. On the other hand, it requires complicated gas treatment and liquefaction systems which results in high delivery cost. Considered that gas engines need gas as final form not as LNG one, if the interim product of LNG liquefaction is simplified, it would be beneficial to overall project economy. As an application example, extensive economic studies for 0.5 MTPA Cluster FLNG, LNG transportation vessel, and 350 MW capacity LNG power plant have been carried out. Typical distance from the gas field to power plant is 2,000 Km though it can have competitiveness up to around 5,000 Km. The smaller unit LNG production system with high competitiveness would activate developments of stranded gas field, and it would change business paradigm by bringing flexibilities and diversities in the industry.
Vassilellis, Katerina (Baker Hughes - Gaffney, Cline & Associates) | Park, Namsu (Baker Hughes - GeoMechanical International) | Prasad, Umesh (Baker Hughes - Reservoir Development Services) | Sakowski, Stephen A. (Baker Hughes - Gaffney, Cline & Associates Ltd.) | Graham, Bryan (Baker Hughes - GeoMechanical International) | Ghadimipour, Amir (Baker Hughes - GeoMechanical International) | Oletu, Joshua (Baker Hughes - Gaffney, Cline & Associates) | Li, Yu Lisa (Baker Hughes)
Deepwater Gulf of Mexico contains numerous geologic plays at different reservoir depths with proven hydrocarbon resource. Among these plays is the Wilcox, where exploration and appraisal drilling has increased since 2001, and reported successes indicate that the play holds significant producible hydrocarbons in the order of multi-billion barrels. However, depth, location, and reservoir characteristics of the offshore Wilcox play present various challenges to commercial development of the Wilcox formation even with today's technology.
This paper summarizes a study that focused on Wilcox reservoir properties. It reviewed publicly available data from the Deepwater Gulf of Mexico Wilcox play. The study identified reservoir and geomechanical properties as well as potential regional trends and challenges facing deepwater Gulf of Mexico exploration and development. In addition, a log-based analysis was used to estimate rock mechanical properties and assess the potential for sand production and compaction. Initially conducted in 2009, this study was updated in 2012 to incorporate additional well data available for the Deepwater Gulf of Mexico Wilcox formation.
As a result, the study has helped to gain a better understanding of the Wilcox play, so that a reservoir life cycle approach can be implemented to serve the energy sector for more informed reservoir development decisions and fit-for-purpose engineering designs.
Shales constitute about 75% of most sedimentary basins, however, studies dealing with their elastic properties and seismic response are relatively few. Mapping the distribution of shale gas sweet spots and identifying their thermal maturity, organic carbon richness and natural fracture network using seismic data are of critical importance for unconventional gas field exploration and development. These studies can be further developed to include the analysis of fracture information from seismic data and VSP data all of which form inputs to a fully coupled geomechanical flow simulator which can be used to forward model fluid flow and accurate displacements and stresses at any location and time. Combining these with the microseismic data both forward modeling and measurement and analysis allows for the generation of a calibrated coupled geomechanical flow simulator to predict to predict drainage areas, production rates and ultimate recovery