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Morosini M.,OMV Austria Exploration and Production GmbH | Daley T.,BG Norge | Eales M.,Senergy GB Ltd | Boivineau A.S.,Schlumberger | And 2 more authors.
Petroleum Geoscience | Year: 2012

The Karachaganak Field is an oil and gas condensate supergiant field located in the western Kazakhstan Pricaspian Basin. As part of the challenge to improve reservoir knowledge, KPO has been continuously monitoring the reservoir using a microseismic array deployed downhole since February 2009. Continuous deep recording of microseismic activity is an innovative technique for reservoir monitoring; progressive refinements were made to fine-tune the acquisition and processing techniques. By December 2010, 8074 events had been detected and, from this group, 2556 events have been located. Events within the reservoir were recorded up to 8 km from the array to a depth of 5 km with moment magnitudes (Mw) ranging from -2.4 to +1. Microseismic events are continuously located and their spatial and temporal distribution analysed. This basic analysis is the input to an integrated study that considers the static model for the reservoir, in addition to dynamic and operational aspects such as production and injection rates, pressure baffles, drilling behaviour and casing perforations. The results to date indicate valuable reservoir information concerning the location of lateral and vertical reservoir pressure baffles and delineation of zones of instability at the reservoir-seal interface, important for well integrity issues. This new information is helping to improve dynamic and geomechanical reservoir models and also wellbore stability predictions. This article presents the details of the Karachaganak microseismic array and how microseismic events were located. Discussion follows on the interpretationand the possible impact on reservoir monitoring and drilling. The Karachaganak array is one of the deepest installations of a passive microseismic monitoring system and also represents one of the longer periods of continuous monitoring, with two years of data available. © 2012 EAGE/Geological Society of London.

Wilkinson M.,University of Edinburgh | Haszeldine R.S.,University of Edinburgh | Hosa A.,University of Edinburgh | Stewart R.J.,University of Edinburgh | And 10 more authors.
Energy Procedia | Year: 2011

In the UK, by far the largest CO2storage opportunities lie offshore. The North Sea in particular has a long and complex geological history, with potential reservoirs geographically widespread and occurring at multiple stratigraphic levels. Diverse storage estimates have been made, using a range of working methods, and yielding different values, e.g. SCCS (2009) [1]; Bentham (2006) [2]. Consequently the UK Storage Appraisal Project (UKSAP), commissioned and funded by the Energy Technologies Institute (ETI), is undertaking the most comprehensive assessment to date, using abundant legacy seismic and borehole data. This study has a remit to use best current practice, consistent between locations, to calculate the CO2 storage capacity of the entire UK Continental Shelf (UKCS) within saline aquifers and hydrocarbon fields. The potential storage formations have been subdivided into units for assessment, and filtered to remove units with only a small estimated storage capacity to concentrate resources on more viable units. The size of potential storage units approximate to a power law distribution, similar to that of hydrocarbon fields, with a large number of small units and a small number of large units. © 2010 Elsevier Ltd. © 2011 Published by Elsevier Ltd.

Mumaw G.R.,Senergy GB Ltd.
Society of Petroleum Engineers - Abu Dhabi International Petroleum Exhibition and Conference 2012, ADIPEC 2012 - Sustainable Energy Growth: People, Responsibility, and Innovation | Year: 2012

The increasing complexity of new exploration targets requires the use of both seismic and non-seismic methods in the exploration process. This is readily achieved by integrated workstation software that enables simultaneous interpretation and modelling of both data sets. Where 2D seismic control is sparse and highly ambiguous, Gravity and Magnetic data provide additional independent measurement of the subsurface; and a more reliable integrated interpretation of complex geologic structure, adding value and reducing risk. Further, continuous improvement in data resolution and sensitivity [from land, marine and airborne acquisition and processing systems] are making completely new applications possible, expanding Potential Fields methods from regional 'reconnaissance' tools into prospect scale and to some extent, reservoir scale, including both 3D full tensor gravity (3D-FTG) and magnetic gradiometry technology. Unfortunately, turmoil in the region has prevented their airborne survey deployment to date but this could readily change with improving political stability in Iraq-Kurdistan. Meanwhile, high quality public domain regional space mission 'satellite derived' gravity and magnetic data provides the focus for understanding and mapping the tectonic framework: basement architecture and distribution of igneous bodies. Structural information so derived can be combined with basement depth estimation to improve understanding of basin morphology, evolution and the petroleum system. It can also prove valuable in identifying continuity between well and seismic data. This paper demonstrates the utility and integration of regional scale public domain non seismic data to assist with the local scale structural model and prospectivity assessments of some high fold zone blocks of interest in NE Iraq/Kurdistan. The Bazian (Block) anticline is used to illustrate a typical local scale feature for evaluation. Copyright 2012, Society of Petroleum Engineers.

McPhee C.,Senergy GB Ltd | Byrne M.,Senergy GB Ltd | Daniels G.,Senergy GB Ltd
JPT, Journal of Petroleum Technology | Year: 2011

Petrophysical analysis has a strategic role in evaluating well productivity and, ultimately, hydrocarbons in place. However, use in formation-damage assessment and evaluation has been overlooked or applied inappropriately. Overreliance on often ambiguous welltest data and a lack of understanding of the formation's static and dynamic petrophysical properties have produced misleading conclusions on formation damage. Two field examples illustrate benefits of a forensic re-evaluation of log, core, and test data in both the recognition and rejection of formation damage in low-permeability oil and gas/condensate reservoirs in which data constraints precluded direct laboratory or field testing to quantify damage potential.

Qutob H.,Senergy GB Ltd | Retalic I.,Senergy GB Ltd
Society of Petroleum Engineers - Kuwait Oil and Gas Show and Conference, KOGS 2013 | Year: 2013

With the majority of today's "new" hydrocarbons increasingly found in technically challenging, complex and in many cases lower quality reservoirs, it's long since been agreed there is no more "Easy oil". It's that fact, coupled to the industry wide challenges associated with conventionally drilled wells in mature and depleted reservoirs which have led in recent years to the very significant advances seen in the Advanced Drilling Techniques (ADT) and Technology arena. ADT provides a suite of tools and techniques which have enabled the technical and commercial development of numerous oil and gas reservoirs worldwide which would have not otherwise been exploited. ADT comprises of the following techniques: • Managed Pressure Drilling • Underbalanced Drilling • Coiled Tubing Drilling • Through Tubing Rotary Drilling (Conventional and HPHT) • Subsea Through Tubing Rotary Drilling According to one recent industry report some 67% of the world's daily oil production comes from mature fields, therefore in order to not only sustain but improve upon current production levels, field life extension is not optional but an absolute necessity. Historically however, most Operators due to cost and complexity of well delivery have not fully exploited their mature assets consequently failing to reach their full potential. Therefore, in order to not only sustain but increase current production levels to meet the increasing demands, operating companies must pay greater attention to their mature fields and their resources development options. The above coupled to the fact that in almost every conventional drilling operation there is risk, a potential to; damage well productivity (formation damage), encounter lost circulation; suffer differential sticking and many other related conventional drilling problems any of which can be exaggerated in a mature drilling environment as a function of depletion. Its here, when applied with an expert system for candidate reservoir screening, technique selection and improved reservoir evaluation technologies, ADT provides realizable and available EOR and IOR options in accessing 'conventionally' or commercially stranded reserves. Further, when fully coordinated with the neseccary subsurface disciplines an ADT solution will add measurable value by; improving production, enhancing ultimate recoverable reserves, even possibly reduce overall development cost all improving net present values. Popular perception is we need new technology to sustain and drive the industry forward in meeting the global demands placed upon it; in truth if we look; much of the required technology is available now. The thing we, the industry, need most is the opportunity and most importantly the courage to deploy it. This paper will challenge us in our perceptions and highlight how we can mitigate the risk applying smarter drilling options such as those offered by Advanced Drilling Techniques in the hydrocarbon bearing formations. Copyright 2013, Society of Petroleum Engineers.

Qutob H.,Senergy GB Ltd | Kartobi K.,Sonatrach | Khlaifat A.,Abu Dhabi Polytechnic
Society of Petroleum Engineers - International Petroleum Technology Conference 2014, IPTC 2014: Unlocking Energy Through Innovation, Technology and Capability | Year: 2014

The increased demand for more sources of clean energy such as natural gas from unconventional reservoirs has forced the industry to explore the more challenging tight gas reservoirs. Tight gas reservoirs constitute a significant proportion of the world's natural gas resource and offer great potential for future reserve growth and production. However, to meet future global energy demand, access to tight gas reservoirs requires innovative and cost effective technical solutions. Yet, tight gas reservoirs are often characterized by complex geological and petrophysical systems as well as heterogeneities at all scales. Exploring and developing tight gas accumulations are both technically and commercially challenging due to the large subsurface uncertainty and low expected ultimate recovery per well. Appraisal of deep tight gas reservoirs offers many challenges, including production rate predictions when wells are drilled overbalanced. Overbalance leads to near wellbore damage to the rock matrix and fractures. Damage to natural fractures intersecting the well can prevent their detection leading to missed productive intervals. In addition, the operating environment is very challenging and that affects the decisions for data acquisition. The use of salt-saturated mud systems creates a contrast and uncertainty in the data. Hence, the quality of data acquired is compromised. In the 80's hydraulic fracturing of deviated wells was the method of choice for developing tight gas reservoirs worldwide. Although sound in principle, in practice problems were experienced and caused either by poor cleanup due to fluid incompatibility, erosion of surface facilities or early water breakthrough due to fracturing into the water leg. In the 90's horizontal drilling became common practice as new drilling technologies developed and proved to be very successful in many tight gas fields. However, conventional drilling operations introduced foreign fluids and solids into the reservoir which lead to several different formations damage mechanisms that prevented the identification of the gas production potential from these wells. In the late 90's underbalanced drilling (UBD) was introduced, mainly to avoid the frequent drilling problems associated with total losses into these tight gas reservoirs. However, significant productivity gains were also observed and this became a key driver to apply the same UBD technology in tight gas fields. This paper provides a technical overview of the state-of-the-art UBD technology used to develop unconventional tight gas reservoirs. Two real case histories from eastern Jordan and South West Algeria will be presented and discussed. Copyright 2014, International Petroleum Technology Conference.

Harrison B.,Senergy GB Ltd
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2013

Natural gas liquids (NGLs) are recovered from the produced wet gas stream by a more complicated process than typical separation that involves additional chilling and compression. Thus, NGL volumes can be obtained by decreasing a field's wet gas production profile, but this should be avoided unless a premium price can be obtained for the liquids relative to the gas that is used to make them. Traditionally, in the evaluation of undrilled exploration prospects in the North Sea, there is so much uncertainty in the forecasts of product prices that analysts tend to only consider oil, condensate and sales gas, when deriving an economic value for a prospect. However, some North Sea Operators routinely offer farm-in opportunities where the probable resource estimates in their prospects, which are assumed to contain volatile oil, are broken down into oil, dry sales gas and NGLs. This practice has come about as the price differential between oil and gas has grown. The upshot is the company farming in will see a higher prospect valuation, and thus receive a lower working interest for the same money it puts on the table. Some say that putting a value on NGLs in prospect evaluation is over-sciencing the process. They argue that as analysts are guessing the hydrocarbon type and its gas in solution, it is going a step too far to claim they can estimate NGL yield too with any confidence. They also hold the view that the range calculated for a prospect's resources should be wide enough to adequately accommodate any additional benefit which may result from NGLs, as they would be taken care of in the noise. Those that support attributing value to NGLs counter that the real issue is a matter of the amount and reliability of the technical data on the opportunity. They argue that if analysts can determine the NGL yield with an acceptable level of accuracy, then it should be considered, provided that one remembers to include the incremental facilities cost of NGL recovery. Both points of view are discussed, in particular whether companies may have under-valued and walked away from past opportunities by failing to put a value on NGLs. By valuing prospects higher, companies can live with a higher exploration risk and tolerate higher drilling costs. The paper briefly considers the ethics of a company adopting a binary strategy of assigning value to NGLs when farming out, but ignoring it when farming in. Finally, appendices provide detailed descriptions of how to use a linear version of the expected value concept for farming analysis and give a simple workflow to estimate potential NGL recoverable volumes for a North Sea volatile oil prospect. Many of the issues discussed also apply to gas condensate exploration targets, but this paper focuses on those prospects that are thought to contain volatile oil. Readers can draw their own conclusions as to which view is better, yet the majority of the feedback from analysts was that many prefer not to assign a separate value to the potential NGL stream from a volatile oil prospect in the North Sea. Copyright 2013, Society of Petroleum Engineers.

McPhee C.,Senergy GB Ltd | Byrne M.,Senergy GB Ltd | Daniels G.,Senergy GB Ltd
Society of Petroleum Engineers - 9th European Formation Damage Conference 2011 | Year: 2011

Petrophysical analysis plays a strategic role in the evaluation of well productivity and, ultimately, hydrocarbons in place, but its importance in formation damage assessment and evaluation has often been overlooked or inappropriately applied. Overreliance on often ambiguous well test data, and a lack of real understanding of the formation's static and dynamic petrophysical properties have combined to produce misleading conclusions on formation damage. Two field examples are presented to illustrate the benefits of a forensic re-evaluation of log, core and test data in both the recognition and rejection of formation damage in low permeability oil and gas condensate reservoirs where data constraints precluded direct laboratory or field testing to quantify damage potential. In the first, the results of the initial welltest interpretation proved decisive in the original operator's decision to relinquish the field license. Forensic re-evaluation of core, log and welltest data indicated that the low oil rates on test were more likely to be the consequence of formation damage rather than poor formation permeability, and challenged the negative skin factor in the original interpretation. Recognition of formation damage and the opportunity to drill a new well specifically to mitigate formation damage have persuaded the new operator of hidden potential in a reservoir that had been condemned to be non-viable. Conversely, in the second example, the poor gas productivity on test was initially attributed to formation damage. However, forensic petrophysical analysis, which integrated log, test and SCAL relative permeability data, demonstrated that the true formation permeability was significantly lower than estimated from logs and conventional core tests. Both examples incorporate dynamic SCAL measurements which are often overlooked in classical static petrophysical interpretations. In these lower permeability reservoirs, relative permeability and stress effects significantly suppress the effective hydrocarbon permeability compared to ambient condition estimates. The workflows and best practices described in this paper have clearly beneficial applications in reservoirs where poor productivity on test does not necessarily represent formation damage or, conversely, the true formation potential. Integrating permeability modelling results with mineralogical information and dynamic SCAL relative permeability data provides a powerful tool for verifying well and production tests; and ultimately, the assessment of formation damage. This integrated and systematic methodology has demonstrably realised the true potential of what were regarded as uneconomic prospects, or has verified that poor productivity is solely a result of poor permeability - not formation damage. Copyright 2011, Society of Petroleum Engineers.

Khlaifat A.,Abu Dhabi Polytechnic | Qutob H.,Senergy GB Ltd
Society of Petroleum Engineers - North Africa Technical Conference and Exhibition 2013, NATC 2013 | Year: 2013

Having different mindsets, academics and industrialists are living in different worlds and pursuing different goals. The Academic is striving for creating new solutions with a high innovation rate, scientific achievements and recognition from peers with a long range perception. The Industrialist thinks in terms of short range goals, prefers proven solutions with a low risk and is mainly concerned with costs, profits and economic survival. In view of that, the deficiency of properly skilled labor across the oil and gas industry is emerging as a significant and complex challenge to Middle Eastern countries' future development. Regardless of the large number of universities, technical graduates and post-graduates added to the workforce, only small percentage of them are considered employable by the rapidly growing industry. Hence, the growing gap between academia and industry is reflected on slight availability of high-quality college/university graduates demanded by the industry. This problem can be overcome by having proper and sustainable industry-academia interactions that help to pass on relevant knowledge. Academic institutions place a great importance to closer interaction with industry and research and development organizations. Some interaction has been witnessed, in the developed countries, between large public and private sector enterprises and academic institutes at a level of industry involvement in technology development. Still, industry support to basic research is almost non-existent in developing countries. Academic institutions laboratories utilization by industry for developmental purposes and for product testing has seen some success. With the establishment of in-house research centers by different industries such labs utilization is on a gradual decrease. Effective collaboration between the oil and gas industry and universities will be critical to the industry economic recovery and sustainable international competitiveness. Industry must also make a sustained effort in supporting higher education by providing the support needed to help students build the employability and technical skills that are so important. The joint research venture can be successful only by proper project preparation and implementation. Some cases of cooperation between academia and Senergy GB Limited will be discussed. A number of key issues to achieve successful cooperation between industry and academia are suggested. The areas in which interaction is possible include industry support to basic research for knowledge creation, industry participation in technology development involving some exploratory work, academic intervention in solving industry problems, laboratory utilization by industry, faculty members' sabbatical leave and industry involvement in curriculum development. Also, the paper proposes that the oil and gas industry should work with universities to: Sponsor students studying subjects relevant to industrial needs. Offer more opportunities for internships, placements, work experience or projects. View working with universities as part of core innovation activity. Integrate an academic research group and an industrial development team to generate useful research results and solutions. Copyright 2013, Society of Petroleum Engineers.

McPhee C.,Senergy GB Ltd
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2012

Core analysis provides the only direct and quantitative measurement of reservoir petrophysical properties and should provide the ground truth for integrated formation evaluation. However variable data quality, the sensitivity of results to different test methods, poor reporting standards, and the reluctance of some vendors to share experience and expertise have all contributed to basic mistakes and poor data quality. It is easy to blame the vendors, but in too many cases, an inconsistent or inappropriate approach to the design, management and interpretation of the core analysis programme has been adopted and exacerbated by the conflicting requests of the end users. In combination, this has led to a situation where around 70% of legacy SCAL data are not fit for purpose. We present a core analysis management road map which is designed to increase the value from core analysis investments by enabling a more pro-active, more coherent and more consistent approach to programme design and data acquisition. Firstly, this involves reviewing legacy data and understanding the impact of rarely-reported experimental artifacts on fundamental rock property measurements. Can data be corrected or re-interpreted or are new tests required? Secondly, a multi-disciplinary core analysis management strategy is described. This is designed to encourage more effective engagement between stakeholders and the data acquisition laboratory through improved test and reporting specifications, pro-active test programme management, and real time quality control. Copyright 2012, Society of Petroleum Engineers.

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