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GEO 2008
- Conference date: 03 Mar 2008 - 05 Mar 2008
- Location: Manama, Bahrain
- Published: 03 January 2008
301 - 320 of 385 results
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Facies and core-based sequence stratigraphic framework for Shu’aiba Reservoir, Shaybah field
Authors Nasser M. Al-Ghamdi and J.F. ReadThe objective of this study was to construct a detailed facies-based sequence stratigraphic framework using cores, logs and available isotope data for reservoir characterization and development. This framework, when integrated with petrophysical data, should lead to better reservoir and simulation models. This study will also help refine our understanding of global climate and sea-level history in the Early Cretaceous. The succession consists of a composite sequence of seven highfrequency sequences and is dominated by 400,000 years (Ky), fourth-order sequences and 100 Ky parasequences. Sequence 1 and part of sequence 2 formed the transgressive systems tract (TST) of the composite sequence with a deeper open-platform of Palorbitolina-Lithocodium
wackestone. The remaining subsequences developed a platform rimmed by rudist rudstone and backed by rudist floatstone back-bank and lagoonal fine skeletal peloidal packstone; slope facies are fine skeletal fragmented packstone. Aggradational subsequences 3 to 5 make up the early highstand systems tract (HST). Progradational subsequences 6 and 7 are within the late HST marking the deterioration of the Offneria rudist barrier and deposition of widespread lagoonal deposits. Shu’aiba
deposition on the platform was terminated by longterm sea-level fall, followed by exposure and karsting. The presence of 400-Ky fourth-order sequences and 100-Ky parasequences, which were driven by long- and short-term eccentricity, respectively, suggests that early Cretaceous climate may have been cooler than generally believed and was not an ice-free greenhouse world. This is pertinent to the debate concerning whether the Aptian was a time of green-house climate typified by small precessionally-driven sea-level fluctuations, or whether there were small ice sheets at the poles that generated moderate-amplitude, fourth order fluctuations, driven by eccentricity.
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Managing data for well geosteering operations
Authors Shixin Wei and Al KokWell data management is a key element in geosteering and operations activities. It requires the well data to be updated in the corporate database in a timely manner, and that the key operations projects have consistent and properly populated well data. With the widespread application of log-while-drilling and monitor-while-drilling (LWD/MWD) technology, satellite data communications with the wellsite, and interpretation in various application projects, the flood of the incoming data requires enhanced data management practices and procedures to ensure that the corporate well data repository is complete and accurate. We have developed a workflow to inspect and integrate the well data in various master and operations projects, which synchronizes them with the corporate database. Collaboration with geologists working in these projects is essential to ensure completeness and accuracy of the data. The data managers ensure the validated well data is loaded into the corporate database and subsequently propagated across related operations projects to ensure consistency for geosteering activities. Several tools have been developed to automatically execute quality assurance and control (QA/QC) procedures. Two examples are used to show the benefits from such a data management approach.
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Climate-controlled meteoric diagenesis in carbonates below unconformities
More LessSedimentologic and diagenetic data are important for the petrophysical characterisation of carbonates because they parameterise reservoir properties and help to predict flow units below the resolution of seismic lines. Among many control factors, meteoric diagenesis affected most carbonate platforms during sea-level lowstands. This diagenetic environment is commonly believed to be associated with increases in porosity, permeability and pore throat diameters. Using data from three carbonate localities, amelioration or deterioration of reservoir parameter was rigorously tested with a three-step approach. In the first step, the study characterized meteoric dissolution and the subsequent late diagenetic products that filled the pore systems. In the second step, sedimentological and diagenetic data was transformed into petrophysical data. In the third step, the importance of climate, especially humidity and aridity, was considered in order to understand meteoric dissolution and infill. The goal of the study is to make petrophysical predictions. Data from outcrop, slabs, thin section and stable isotopes were used to establish three scenarios that summarized significantly different processes involving meteoric diagenesis below unconformities: (1) increase of porosity and permeability and their preservation through time; (2) increase of porosity and permeability and subsequent pore system occlusion; and (3) decrease of porosity and permeability and creation of a barrier for pore fluids. Knowledge of the texture of the host rock,
the time span involved in meteoric diagenesis and the climate regime are necessary to predict porosity and permeability of meteoric pore systems. The study provided evidence that a well-connected karst system is likely to be filled with sediment and cement, whereas smaller pore systems have the potential to remain open during basin development under more arid conditions. Depending on the aforementioned parameters, end-members of meteoric diagenesis are either seals or rocks with good reservoir properties.
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Basin platform transitions in Upper Jurassic carbonates of the Amran Group, Yemen
More LessThe Amran Group consists of an 800–1,200-m-thick carbonate sequence. Outcrops in the Yemen mountains consist of shallow-water facies types with shallowing upward cycles. In the study area, the Marib Province, those facies types inter-finger with basinal facies types of the Marib-Sabwah Basin. Facies analyses made on thin sections of several profiles, X-ray diffraction (XRD) analyses of the insoluble residue and geochemical datasets were used to reconstruct the transition between the deeper-water basin facies and the shallow-water facies types of a carbonate platform. A sedimentary ramp setting can be reconstructed by the lateral distribution of the different facies types. They show a low slope with ooid sandbars and lagoonal facies types, which change to fossil wacke and packstones of a deeper-water setting. The basin facies is represented by mudstones. The stratigraphy is based on foraminifers, and supported by clay mineral and chemostratigraphic analysis. One focus of the study is the position of reefs on the carbonate ramp. They appear as different types depending on water depth, and can be divided based on the composition of reef-building organisms.
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Seismic character of a fractured reservoir: A physical model study
Authors Robert W. Wiley, Byron Golden and Peter Wilson and Scott PetersWe designed a physical model to study the effect of a swarm of vertical fractures on seismic data. The physical model was constructed by placing several glass slide covers between two large glass blocks. This was then embedded in resin to represent the bounding lithologic layers above and below the fractured zone. The glass slide covers were approximately 0.5 mm in thickness and adequately represented fractures when scaled. 3-D seismic data was collected over this model using high-frequency transducers with a variety of offsets. By comparing the amplitude-versus-offset (AVO) response over the glass blocks with the AVO response over the fractures, we determined the variations in AVO due to the fractures. We were also able to analyze spectral variations between the fractures and the unfractured block. In addition, we determined spectral variations with offset of the fractured portion of the model. These results will enable the explorationist to better determine the location and orientation of fractured reservoirs.
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Seismic frequency variations of a reservoir: Lessons from a spring
Authors Robert W. Wiley and Peter Wilson and Scott PetersIn studying wave propagation and attenuation in the Earth, it is often convenient to use simplified models. One of these models is a mass, spring and dashpot to model oscillation and attenuation. By analyzing the motion of a spring using different forced oscillations, we studied the effect of the system’s characteristics on the transmitted frequency. In particular, we observed that if the forced oscillations are above the system response, the predominant output will be at the system characteristic. For lithologic layers, the system characteristics depend, in part, upon the Poisson’s ratio, matrix and the fluid velocities. With reservoirs having different fluid velocities and often different Poisson’s ratios from the surrounding rock; this implies that hydrocarbon reservoirs could have a measurable spectral character based upon their unique system or rock properties and that these characteristics could be estimated with seismic data.
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Cycle time reduction and integration - seismic to simulator
Authors Hamish A.M. Wilson and Olivier S. E. Van BelleThe industry continues to search for ways to increase productivity and reduce overall finding and production costs. Integrated processes are critical to achieving the necessary productivity gains. The seismic to simulator process is fundamental to reservoir management. Huge gains have been achieved in the time taken to rebuild a reservoir model, however further challenges remain. Consider two issues. Firstly, The increasing availability of real-time production information from smart field-type initiatives requires the reservoir model to be updated more frequently, perhaps in real time. We are struggling to combine the long reservoir model cycle with real-time production data. Production operators should be able to use the reservoir model to support day-to-day field
management decisions. Secondly, reservoir performance data should be used to inform the static model and influence the geological and geophysical interpretations. Both systems and people barriers have to be overcome in order to achieve the further productivity gains outlined above. On the systems side, barriers remain in the integration of the static to dynamic model. Within the static domain, technologies like OpenSpiritTM plus the efforts of Schlumberger and Halliburton have enabled huge gains
in static model integration. Yet moving geological models into the simulator is not easy. These challenges can only be addressed by considering the subsurface model as a single integrated process. Yet in many companies, geologists, geophysicists and engineers are in separate organisational structures that do not communicate. We have to solve the people problem first before addressing the systems integration issues.
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Reactive transport modeling and reservoir characterization: recent advances in geoscience and engineering applications
Authors Yitian Xiao and Gareth JonesOne of the key challenges in reservoir characterization is the accurate prediction of reservoir quality distribution and alteration associated with various diagenetic reactions at both geological and production timescales. Reactive transport modeling is an emerging technology that can be used to simulate ground-water flow coupled with chemical reactions to facilitate predictions of the dynamic reservoir behavior of multi-phase fluid-rock interactions. We have applied reactive transport modeling to a number of case studies that significantly advanced our reservoir characterization capabilities for both geoscience and engineering applications. For example, we have developed the first fully-coupled 3-D reactive transport models for dolomitization in both early reflux and late fault-controlled hydrothermal systems. The modeling results revealed complex spatial and temporal variations of limestone, dolomite, and anhydrite distribution and the significant implications on carbonate reservoir quality. Other successful applications included modeling early diagenesis associated with a fresh-water lens in an isolated carbonate platform; geothermal convection and burial diagenesis in a salt-buried isolated platform; and fault-induced hydrothermal flow and illitization and permeability reduction in a sandstone reservoir. For engineering applications, we applied reactive transport modeling to study formation damage associated with water and steam injections in sandstone reservoirs; acid stimulations and worm-hole development in carbonate reservoirs; and the long-term fate and risks of injecting CO2 and H2S in saline formations. Modeled positive and negative feedbacks induced by artificial diagenesis provided guidance to optimize injection strategies. Reactive transport modeling, when sufficiently integrated with
traditional methods and calibrated with field data, has the potential to generate physically viable predictive concepts and reduce the uncertainty in predicting the spatial distribution of reservoir properties that impact both geoscience and engineering business decisions.
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Structural restoration as an effective tool for detecting the evolution and timing of structural development: A case study from the Muglad Basin, Sudan
More LessThe area under investigation is located in the Muglad Basin, which is mostly covered by 2-D seismic data with fair to good quality. Three wells were drilled in this area, two of them were dry and the other one is currently producing from reservoirs such as AG-2 and Bentiu. Faults in the study area trend E-W whereas in the rest of Muglad Basin they trend NW-SE. The main objectives of this study were: (1) to evaluate the vertical migration through the faults; (2) establish the time when the structural trap formed; and (3) understand the geological evolution of the area. Five regional 2-D seismic lines were selected to conduct a structural restoration. An inclined shear algorithm was utilized because of it’s applicability for extensional tectonic regimes. Both reconstruction and flattening approaches were applied. The extension ratio (Beta) was used to predict the rift-sag periods. The rift stage was characterized by high Beta values (e.g. 1.2), while the sag period ranges for Beta varied from 1 to 1.1. This sub-basin evolution history consisted of three rift phases. The first occurred during the Early Cretaceous and was the most long-lasting. The second phase, which occurred during the Late Cretaceous, many faults were initiated and others were re-activated. In the third rift phase, which occurred during the Tertiary, many faults were initiated. The study area is located near the Central African Shear Zone, which control the faults orientation. Generally the faults were formed by dextral oblique movements. The validity of the traps has been confirmed through a restoration process.
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Workflow automated services for well logs
Authors Ghassan Omar Zahdan and Marwan Mohammad LabbanSaudi Aramco’s Reservoir Description Division (RDD) provides well log services to the company’s professionals including archiving, processing and publishing in a timely and efficient manner. In recent years the volume of work has increased considerably and this has prompted RDD to seek assistance from the Formation Evaluation Systems Group (FESG) to implement the Workflow Automated Services for well Logs (WASL) System. The workflow allows E&P producers and users to collaborate in delivering higher quality certified well log results. Also, the system provides RDD engineers with an easy mechanism to archive raw well log data, and then track and monitor their processing. The results are automatically published into a corporate repository where they are accessible by authorized well log users throughout Saudi Aramco. The system monitors service companies and Saudi Aramco responsiveness and accountability. It ensures timely well log service availability to Saudi Aramco well log users.
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Improved wellbore stability modeling in fractured formations
Authors Jon Zhang and Eamonn Doyle and William StandifirdOne of the most prominent features of the Earth’s upper crust is the presence of joints and fractures. Many petroleum reservoirs are situated or inter-bedded in these fractured porous formations. For instance, fractured carbonates and fractured laminated shales are prevalent in the giant and prolific fields of the Middle East; the Ekofisk formations in the North Sea comprise fractured chalks. Drilling in these fractured formations presents wellbore stability challenges because the fractured rocks have larger shear failure zones and smaller fracture gradients. This results in a narrower safe mud-weight window, and wellbore instability-related costs can become great because of lost time or, in the worst case, a lost well. A double porosity poroelastic model has been proposed and the finite-element method was applied to obtain a wellbore stability solution. This method considered the effects of both fractures and porous media on wellbore stress redistributions, and hence can better model fractured porous media. A case study in Oman
was examined, where claystones were weak and carbonate rocks were heterogeneous and contained natural fractures. Wellbore-stability incidents, such as drilling fluid losses and massive wellbore breakouts, frequently occurred while drilling. These problems were mainly caused by the narrow mud-weight window available for maintaining wellbore integrity. Increasing mud weight caused drilling fluid losses, but lowering mud weight induced wellbore breakouts. After modeling, analysis, and calibration in the offset wells, the correct mud-weight window and casing intervals were recommended for proposed wells to avoid wellbore shear and tensile failures.
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Evaluation of the slip-sweep technique near southwest Ghawar field, Saudi Arabia
Authors Turki M. Al-Ghamdi and Julien Meunier and Thomas BianchiA 14-swath seismic acquisition experiment was conducted in November 2006 over a prospect area southwest of Ghawar field. The objective of this experiment was to compare four source designs with various numbers of vibrators in flip-flop or slip-sweep modes. The receiver geometry (4,400 receivers, interval 50 m) and sweep frequency range [4–94 Hertz]) were kept constant throughout the test. For each array, the parameters were as follows: (1) number of vibrators/fleet 5 3 2 1; number of fleets 2 4 4 12; (3) Sweep length (second) 15 15 15 42; (4) Slip time (second) Flip-flop 11 9 5; (5) Source density (VP/km) 200 400 800 800; (6) Actual productivity (km/ hour) 0.51 0.54 0.32 0.8. It is clear that the slip-sweep method can provide a very significant improvement in
productivity compared to flip-flop acquisition. Two questions remain: (1) is vibroseis source-generated noise or ambient noise the limiting factor? (2) How will the additional noise associated with the slip-sweep method affect the seismic image? The conventional fivevibrator 0source array design has proven to improve the initial signal-to-ground roll and ambient noise ratio. These source arrays can be decomposed into single-vibrator, point-source efforts, maintaining the same source density per area while increasing the sampling density. This improved source sampling optimizes source-generated scattered noise attenuation methods. Preliminary analysis of stack data showed equal quality for the fivevibrator and the three-vibrator data; but the single-vibrator achieved better quality although the square-root theory predicted a signal-to-noise ratio of 3.5 decibels lower. This seems to indicate that source-generated direct and scattered noise is indeed the problem in this area and that it is serious enough to mask the additional noise associated with the slip-sweep method.
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Managing and populating scanned exploration geology and geophysics data in GIS
By Larry ZhangMany oil and mining companies are increasingly leveraging the power of geographic information systems (GIS) to better manage geospatial data. This includes massive scanned (from hard copies) geological and geophysical (G&G) data such as cross-section, well logs, 2D/3D seismic, even exploration reports. They are also seeking to insure that cross-disciplinary spatial data is readily available to their geoscientists and explorationists, because most exploration geodata is spatially-enabled and time-associated. In order for geoscientists to use the powerful and extensive GIS environment for G&G projects, G&G geodata (including scanned) are firstly required to spatially enable them in GIS database like ArcSDE with open standards and data models like PPDM, POSC. The presentation briefly reviews two of current commonly used techniques for managing G&G geodata, including project-based E&P databases and the Documentum technique, and some disadvantages. And then, it mainly presents how to spatially manage scanned G&G geodata in GIS database; and explain how to integrate and populate those geodata for any E&P projects in order to reduce risk in exploration activities. From a perspective of G&G management, I will also discuss how to ensure the scanned G&G geodata are complete to deliver so that explorationists can receive them under various spatial query criteria and time conditions, no matter where and when the exploration projects happen.
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Prediction of top surface movements due to SAGD (steam assisted gravity drainage) based on coupled thermal pressure deformation models
Authors Xing Zhang and Nick KoutsabeloulisSteam assisted gravity drainage (SAGD) is a new oil production technology for the recovery of heavy oil and bitumen. In these fields, the top surface movements that are caused by thermal expansion of reservoir rocks due to injected steam, is a major concern in many environment issues. This is particularly true for those faulted reservoirs that are close to the top surface. A coupled thermal-pressure-deformation model has been used to predict the movements of overburden on a cross-section of a studied field, the associated changes in stress and strain and the potential for fault reactivation during a production period of 33 years. This field has a reservoir thickness of about 250 m, overburden thickness of about 350 m, temperature change of up to 190° C and pressure
depletion of up to 190 psi. The intact rock was simulated as an elasto-plastic material and the faults were simulated as Mohr-Coulomb materials. Four scenarios were examined to account for the uncertainty in mechanical properties of overburden and reservoir rock, such as Young’s modulus, Poisson’s ratio and thermal expansion coefficient. After 33 years of production, about 0.155 m of upward movement at the top surface above the reservoir was predicted under the given conditions. Also there is a high risk for fault reactivation due to the expansion of the reservoir rock. The predicted upward movement of the overburden decreases with decreasing Young’s modulus and thermal expansion coefficient, and increases with increasing Poisson’s ratio due to the increase in bulk modulus.
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Investigation of effects of well configurations on reservoir recovery efficiency based on coupled geomechanical models
Authors Xing Zhang and Nick Koutsabeloulis and Kes HefferThe impact of well configurations on reservoir recovery is investigated based on a coupled geomechanical model. This areal model simulated 36 months of production and injection in 49 wells in a stressed and fractured-faulted reservoir, which is geologically similar to the Gullfaks reservoir in the North Sea. The coupled model is capable of simulating the interaction between reservoir rock deformation and permeability changes, both in intact rock and in fractured-faulted rock. The intact rock was simulated as an elastoplastic material, and the faultedfractured rock as a Mohr-Coulomb material. Three scenarios of well configurations were investigated. The same sequence of random, uncorrelated pressure changes at wells was input in each case, and the consequent
production and injection rates at wells were output for analysis. In Case 1, there were 25 producers and 24 injectors, in which each producer was surrounded by 4 injectors. In Cases 2 and 3, there were 28 producers and 21 injectors with 4 rows of producers and 3 rows of injectors, but the direction of rows was different in relation to the regional horizontal stress direction and the major faults. Due to the difference in well configurations, significant fracture-related permeability enhancement occurred in Cases 1 and 3, which resulted in significant difference in total production rates and injection efficiency. The total production rate was about 75% higher in Case 1 than in Case 2, and the injection efficiency was about 20% higher in Case 1 than in Case 2. In addition, Spearman rate correlation coefficients were used to identify the most efficient production-injection wells. The study revealed a very strong influence of geomechanics on the reservoir performance.
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Spatial reservoir localization using seismic emission
All geological media are active seismic systems that, in themselves, generate microseisms. Microseismic energy generation is generally disregarded in most theories, but not in seismology and microseismic studies. In particular, seismic tomography can be used to model noisy objects (microseisms) localized in an half-space model of the Earth, including hydrocarbon reservoirs. We have conducted experiments, using three-components accelerometers, to investigate natural seismic-acoustic emission (SAE) with a view to applications to hydrocarbon reservoirs. The goals of the experiments were to investigate the SAE’s character, its frequency content and distribution for all three components along test lines. The final objective was to develop a special technology for
the spatial localization of the reservoir and the definition of its parameters. We found that the SAE activity of the vertical and horizontal components along the test lines correlated with the location of the hydrocarbon reservoir. There were some different frequency ranges in the amplitude spectrum of the SAE, which relate to different noise sources; these difference may be due to the origin or location of the sources. The data analysis showed that special processing based on the principles of seismic tomography may be used to localize the areas of possible reservoir development. The analysis also identified interstitial zones below the mapped reservoir zone, which may be fault-related, oil-migration pathways. We also found that it is possible to use industry vibroseis data
and standard technologies for tomographic analysis of the SAE.
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Restoration of seismic amplitude using a frequency-dependent gain function
Authors Weihong Zhu and Khalid O. Al-RufaiiIt is well known that the Earth absorbs acoustic energy and that high frequencies lose their energy faster than lower frequencies. The loss of seismic energy can be attributed to several factors such as absorption, geometrical spreading, and scattering of energy at an interface due to reflection, refraction, conversion, and transmission. Deconvolution and (Q) attentuation-compensation operations are usually performed in order to restore as much of the attenuated high-frequency energy as is justified by the signal-to-noise ratio. The conventional approach for amplitude recovery is to compute and apply a time-dependant gain function. Here, we extend the conventional exponential gain function to account for the inelastic attenuation effect as well. We introduced a frequency factor into the computation and application of the exponential gain function to account for the inelastic attenuation. This process was performed in the frequency domain. There were three steps involved in the computation. First, a 1-D forward Gabor transform was applied (small windows fast Fourier transform). Next, frequency-gain curves and inelastic attenuation were computed and applied for each Gabor slice. Finally, the data was transformed back to the time domain. It is worth mentioning here that the geometrical spreading, which causes the loss of seismic amplitude can be recovered either before or after the 1-D Gabor transform with no visible difference as was indicated by our extensive testing. Moreover, the two processes of the seismic-energy restoration are reversible. This further enhances the robustness of our methodology. We demonstrate the accuracy and effectiveness of our proposed approach using both synthetic and real data examples.
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Reservoir characterization and 3-D modeling using combined techniques from well logs to reservoir simulation: Case study in the Serie Inferieure, Hassi R’Mel field, southern Algeria
Authors Nennouche Zohra and Azoug Youcef and Belabed KarimReservoir characterisation is a key aspect in building a robust reservoir model for reliable simulations, especially in our case where the reservoir is not yet producing. This presentation describes a method used to build a geological model that was converted into a reservoir model for the Tagi Series of Hassi R’Mel South field (HRS), located onshore in north-central Algeria. The study used PetrelTM software combined with new techniques to preserve the complex variations of the reservoir. Optimising field development required a level of reservoir description that adequately defined vertical and lateral variations in reservoir quality. The method consisted of integrating seismic, petrophysical and geological interpretation. The HRS reservoir formation, known as the Serie Inferieure (SI), has medium to low reservoir quality. The structural model showed great complexity. The results of drilling of three wells, gave 8 m of oil with an average permeability of 50 mD. This encouraged us to develop this reservoir by drilling additional wells before starting production. The SI reservoir represents a challenge for optimising the field development because the heavy oil is located in a highly heterogeneous fluvial reservoir with poor petrophysical conditions. The most important obstacle is that some of the well logs are difficult to interpret due to the naturally radioactive host rocks. The high gamma-ray logs have a high-amplitude response, which masks the reservoir. Another difficulty is that water saturations appear to be very high when interpreted from well logs. To address these problems a multi-disciplinary team used both geological and engineering techniques to develop 3-D numerical models for the effective porosity, permeability, water saturation and facies distribution. These models will be used to calculate the hydrocarbons-inplace and to plan future wells.
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Gas while drilling-fluid reservoir characterization – a new geochemical approach to characterize Radhuma’s heavy oils
In Kuwait Oil Company (KOC), a geochemical mud log (GML) was developed to help analyze the quality of hydrocarbons associated with the different formations in real time utilizing Haworth’s Ratios as recorded by the gas chromatograph. By using this cost-effective GML tool it is now possible to reliably identify promising hydrocarbon zones. It is also possible to predict the composition and the nature of the subsurface fluids. A relationship has been identified that links total gas counts to the commerciality of accumulations, while GML ratio parameters predict the nature of fluids present. Therefore, integration of the GML ratio parameters with total gas counts can quickly identify potential hydrocarbon zones. When used in combination with drilling rate, lithology and other e-log parameters, the method appears to be a useful method to help select intervals for perforation. Recently, KOC has produced the GML in real-time thereby, helping us prepare and or modify the forward programme. However, with further evaluation
we have found that there are some limitations to GML interpretations. During drilling, KOC often uses two types of drilling fluids: water-based mud to drill the section down to the upper Barremian - lower Hauterivian Zubair Formation, whereas, the deeper section is often drilled with oil-based mud. Here we have chosen four exploratory wells A, B, C and D with GMLs distributed across the Greater Burgan field to illustrate the lateral differences in hydrocarbon quality. They are also important in our evaluation of heavy-oil accumulations in secondary reservoirs in the same area such as the Radhuma Formation (Paleocene). Therefore, GML analysis of the gas and or fluid system seen while drilling may indicate higher potential than currently believed. GML evaluation can also provide evidence of: (1) biodegradation and its extent; (2) possible mixing of microbial and thermogenic gases; and (3) the vertical distribution of hydrocarbon quality.
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Partnering to develop a national workforce: Practical challenges and solution
More LessThe challenges facing the Middle East region include increasing the oil production capacity and ageing of the production facilities. To meet these challenges we must have a national workforce capable of achieving these goals. The creation and subsequent development of this national workforce is not an easy task. This presentation concentrates on the practical challenges that face all national oil companies in the region and how to overcome them so as to develop the required local force that can deal with the industry’s technical challenges. The presenter has trained more than 2,500 geoscientists and engineers from the entire region since 2004.The analysis of these short and long-term training sessions has led to the identification of some barriers to build this national workforce; for example: English language skills, sequential courses without on-job-training, early jump toward software-learning before walking through the technical basics, the wrong person in the wrong course, course contents, unqualified instructors, student’s aptitude and attitude and non-technical culture. The solutions to these obstacles include updating the course contents, using local examples, improving the work ethic of local employees, training them on character and not only technical skills, involving supervisors more with participants, using domestic experts as teachers, increasing the cooperation between academia and operating companies, and making sure the right attendee is in the correct course. The Middle East contains 67% of the proven
world oil reserves. It has a talented and young generation and owns the technology to make it happen. What we need to do is to walk the talk.
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