Hydrocarbon in place volumes are often inaccurate as a result of poor representation of the reservoir structure (by means of a 3D grid), that in combination with the use of traditional saturation calculation methods, lead to erroneous hydrocarbon volumes and poor investment decisions.
Traditionally a reservoir model is represented with a 3D grid, in a complex setting such as fault intersections and stacked reservoirs. A corner point grid is often used, which has limitations to represent this complexity. Further, the hydrocarbon saturations are then derived on a cell by cell basis on that 3D grid using simple averaging techniques of saturation height functions. The poor structure representation on the pillar grid in addition to the simplistic averaging methods lead to inaccuracies of the in place volumes especially where a prominent transition zone is present.
This paper presents new advanced saturation averaging methods (volume and height weighted) using saturation height functions on 3D grids. The new advanced saturation averaging methods are used on different reservoir models to compare the saturation distribution and volumetric differences against the traditional saturation calculation methods. A 4-way dip closure reservoir model with a tilted free water level (typical example of a carbonate reservoir in the Middle East), and a faulted S-grid model of the F3-FA field (North Sea) are used.
For the 4-way dip closure reservoir model, when comparing the advanced ‘volume weighted’ and traditional ‘by center of the part of the cell’ saturation averaging methods, a significant difference in the water saturations is observed which leads to about 5% difference in the calculation of in place hydrocarbon volumes. Further, it is observed that changing the thickness and orientation of the 3D grid cells can result in even larger differences of 5-10%.
The faulted F3 model shows that the difference between the hydrocarbon saturation values is largest where it matters most, that is, around the fluid contacts and in the transition zone. The new advanced saturation averaging methods give accurate hydrocarbon saturations irrespective of the size or complexity of the 3D grid and without any discretization effects.
More than 60% of gas reserves in the Middle East region are regarded as sour. The development of sour oil and sour gas fields or originally sweet oil fields, which undergo a souring process during production live, impose significant investments for the H2S treatment and increase significantly the field operation costs. In order to evaluate the origin and development of the H2S in a production system multiple locations covering all process stations such as down hole, well head, separators, gathering stations, pipelines have to be sampled an analysed. The in-field measurements of the H2S concentrations and various laboratory analyses like S34 / S32 isotope ratio, CSIA, DNA sequencing, MPN and Bacterial growth tests could be performed in order to provide a conclusive picture of the H2S contamination.
The most promising and cost efficient technology is the analysis of the bacterial activity using DNA analysis and bacterial growth tests. The integration and interpretation of all above mentioned analysis types is key for the evaluation of the origin and development of the field souring process and provides a robust analytical basis for remediation, scavenging and mitigation operations. In combination with modern dynamic reservoir modeling tools, which allow the history match and forecast of the field souring process, the efficiency of mitigation or scavenging operations in the subsurface and at the surface can be simulated and optimized.
In context with the envisaged production enhancement, the application of EOR technologies and the souring of several reservoirs due to injection, the monitoring and handling of additional H2S production become an important environmental and economic factor.
Conventional methods for wettability assessment are based on volumetric measurements such as displacement tests, and have to be modified for shales because of their low porosity, ultra low permeability with natural fractures, and reactive components. These methods are time consuming and the results are often questionable; these facts that have motivated the search for new approaches to estimate this property. A methodology for measuring shales wettability that uses X-Ray Photoelectron Spectroscopy (XPS) is presented in this paper. Results are compared with conventional imbibition tests. XPS is being used as a faster way to infer the wetting condition on sandstones rocks.
XPS allows knowing the chemical composition of the outer layers of a solid surface. Using XPS the organic carbon content at the surface is evaluated, and then it is correlated with the wetting condition from imbibition tests. Water wet and oil wet shales from different countries were investigated. Samples were prepared rigorously for mineralogical and XPS measurement.
The relationship between wettability and surface composition as determined from XPS is reported. Wettability index measured by imbibition tests is used in this study as an indicator of the wettability of shales. The XPS spectra of oil-wet surfaces of shales reveal the existence of organic carbon and also of an organic mineral species such as Si–CH. These species have a well-defined binding energy which differs from the inorganic species of mineral grains. In this study we present quantifiable evidence that chemisorbed organic material on the surfaces defines the oil-wetting character of oil shales. In the case of gas shales gas is adsorbed onto clay surfaces, as well in natural fractures and porous giving them oil wet condition. This view is supported by a strong correlation between the organic matter content on shale surfaces, the mineral composition and the wettability. In this paper we demonstrate a different approach for measuring shale wettability using XPS analysis. Instead of waiting for many days for the results from imbibition test, XPS takes less than one day. As a result, the time needed for the wettability measurement is reduced significantly.
Numerous oil and gas reservoirs in Kuwait are suffering from H2S contaminations. The H2S concentrations in the affected reservoirs vary significantly from low ppm ranges up to 40%. The H2S concentration levels are related to the generation processes. The high H2S concentrations observed in the Lower Jurassic reservoirs can be related to the TSR process. The dominant H2S generation process in the Upper Jurassic and Lower Cretaceous reservoirs is the thermal cracking of the organic sulphur compounds (OSC) occurring in the Najmah and Sargjelu source rocks. The H2S contaminations observed in the Cretaceous reservoirs show indications of multiple H2S sources. The bulk of the H2S in these reservoirs is generated in situ by the BSR process. In some fields clear indications for H2S migrated from deeper horizons e.g. via faults are observed.
H2S contaminations are also observed at the top site facilities at various stages of the production process. The source for those contaminations is only partly in the subsurface. In several cases a distinct increase of the H2S contaminations of the fluids on its way from the reservoir well to the processesing facilities is observed.
New sampling and analytical technologies tailored to the H2S problematic have been developed, which support the selection of the appropriate mitigation or remediation strategy. The utilization of modern low cost DNA sequencing technologies for the analysis of the bacteria and archea species provide essential information for the design of appropriate chemical cocktails for the mitigation.
Reservoir modeling and forecast technologies have been developed to predict the development of the H2S concentrations in a reservoir. However, for a reliable forecast - irrespective which modeling system or tool is applied - the understanding of the H2S generation process is essential. Furthermore good quality and reliable H2S measurements are mandatory for the history match.
The mitigation and remediation of H2S is a major cost factor in the field development and operations. Field souring i.e. the increase of the H2S concentration during field life is the worst case scenario, which could cause major investments to assure field production. Not only the costs for the H2S treatment materials (e.g. biocides, nitrate) but also the investments in corrosion inhibitors, H2S resistant pipes, valves, filters, and the upgrade of the processing facilities have a large financial impact. Furthermore HSE related measures and required safety and monitoring systems are increasing substantially the operation costs.
In view of KOC's ambitions to increase the oil production by 20% by 2020 and the subsequently expected increase of H2S production, a contry-wide coordination of the treatment concepts for the H2S could improve the efficiency of the mitigation operations and could potentially reduce the investments and operation costs related to the sour gas issue.
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Humans play a vital and centric role in RPAS operations; research has indicated that this role is more complex than conventional aviation and safety critical activities such as commercial infrastructure inspections, testing and data collection. As this industry explodes like a supernova and RPAS operators become more prevalent in the commercial aerospace, we have to ask a deeper question, who is operating the system at the front line ?
The success of the emerging RPAS industry will be determined by the willingness and ability of RPAS crew and the end users to employ aviation safety philosophies, disciplines and the proven aviation safety culture model. The RPAS industry needs more than a compliance philosophy to harness success; the key to this is a positive commitment to develop an
Fortunately, lessons learned from 110 years of aviation have been recognised as crucial to operational success by other safety critical industries, such as the medical, industrial, nuclear power, utilities and other industry sectors. It is now time for the application of this type of safety culture to progress into the commercial RPAS world, a new generation of
KOC and SGS performed a regional scale study to assess and forecast the H2S risk in the onshore sector of Kuwait. Based on KOC's comprehensive data base of H2S measurements, fluid chemistry, geochemical and lithological data, the H2S concentrations in the various hydrocarbon systems in Kuwait were mapped. The origin of the H2S in the Mesozoic reservoirs were analyzed and four major H2S systems were identified. The origin of the H2S in the Lower Jurassic is the TSR process with a pronounced regional trend of H2S concentrations increasing from 0.5% in the south up to 40% towards the north. The H2S encountered in the Upper Jurassic and Lower Cretaceous reservoirs originates from the cracking of sulfur in the Najmah source rock occurring during the early maturation process. The maximum H2S concentrations recorded in these systems does not exceed 5% and no regional trend of the concentrations is observed. The exceptions are overpressured carbonate stringers in the Upper Jurassic Gotnia and Hith formation which have local occurrences of more than 10% H2S. The Upper Cretaceous reservoirs in several oil fields show distinct H2S anomalies up to 5 %. Some of the anomalies possibly are related to field operation activities (e.g. injection) but also evidence for H2S migrated from deeper strata was found. Also indications for H2S scavenging in the Upper Cretaceous reservoirs was observed but could not be quantified. Some of the Tertiary heavy oil accumulations in the north which show high H2S concentrations could be related to the BSR process, however not all heavy oil reservoirs seem to be affected. A forecast of the future development of the H2S concentrations of each H2S system was performed.
Al Saman Al Neaimi, Mai (Zakum Development Co.) | Tee, Aaron Sin (Zakum Development Co.) | Boyd, Douglas (Zakum Development Co.) | Al Shehhi, Rashed (Zakum Development Co.) | Abdel Aziz Mohamed, Emad (Zakum Development Co) | Namboodiri, K.M.N (Zakum Development Co.) | Al Junaibi, Hamad (Zakum Development Co) | Al Zaabi, Mohamad (Zakum Development Co) | Al Braik, Haitham (Zakum Development Co.) | Ftes, Suleiman (Zakum Development Co.) | Medjiah, Abdul Kader (Zakum Development Co.) | Farouz, Ameer (Zakum Development Co.) | Gao, Bo (ExxonMobil Upstream Research Co.) | Gay, Mike (ExxonMobil Upstream Research Co.) | Tariq, Syed M. (ExxonMobil Production Co.) | Fudge, Blake (SGS) | Collett, Paul (SGS) | Gill, Tim (SGS) | Anis, Abdul-Hamid (ALS Corpro) | Schipper, Bas (ALS Corpro) | MacDonell, Sheldon (ALS Corpro)
Pressure core is the gold standard of reservoir saturation determination retaining gas and oil in an enclosed container preventing hydrocarbon loss to the mud system during retrieval of the core to surface. The technique is underutilized in the oil industry due to safety concerns, short coring lengths (3 to 7 feet) per trip and small core diameters (1.6 to 2.6 inches). A new elevated pressure coring system addresses these concerns. The system does not maintain true formation pressure but reduces the core barrel pressure to less than 1,000 psia for safer working conditions on surface. Upon arrival at surface, the core barrel and accompanying gas/liquid collection canisters are blown down and gas/liquid volumes measured and analysed. Free oil is gathered and stored for later analyses. Core diameter is 4 inches and core length is 10 feet.
Zakum Development Company (ZADCO) operates a gas injection pilot in a large carbonate oil reservoir. There was a need to determine field remaining oil saturation after gas flood (ROSg) in a gas injection pilot. Pressure coring was selected as the best technology to obtain this data. This paper covers the planning and implementation of a successful elevated pressure coring operation in the U.A.E., the operational aspects, special core handling techniques, issues encountered and solved. Recommendations are made for future pressure coring operations. A follow up paper will cover the core and fluid analyses aspects.
Compositional data is a vital input to many engineering models, including the calculation of the mud free properties of reservoir fluids sampled by repeat formation testers and calculating the value of gas sold on a calorific value basis. For all such applications, the quality of compositional data is of critical importance. The impact can be material in a wide range of issues, including reserves estimation, facilities design, gas hydrates prediction and sales gas valuation. The main aim of this study was to set quantitative criteria for screening laboratories prior to tendering for a PVT contract.
Reliance on contractor quality assurance procedures is not sufficient. Routine internal consistency checks may not identify some of the errors. Evaluation based on analyses of identical field samples relies on one data set being of high quality, an assumption that may not be correct. There is a need for an independent supplier of high quality gas, liquid and live fluid samples of accurately known compositions that can be used by laboratories to demonstrate the quality they can achieve to the oil companies before unique and valuable samples are sent to them for analysis.
The results of a "Round Robin?? evaluation of PVT laboratories around the world are presented. A set of identical samples was sent to each laboratory - 3 dry gases, 3 stock tank liquids and one live sample. There was considerable variation in the quality of compositional analyses reported. A small minority of the laboratories tested generated compositional data that fully met the highest quality measures for both gas and liquid analysis. A similar number were close to meeting these standards, but the majority generated data that was deeply flawed in some respects. In one case, interpretation errors resulted in 24% reduction in C4+ in all the gases. The resulting calculated calorific values were as much as 5% low - a large potential loss of value if used to calculate the value of sales gas. All laboratories were given feedback, and some are actively engaged in resolving the problems identified.