SPE, through its Energy4me programme, will present a free one-day energy education workshop for science teachers (grades 8–12). A variety of free instructional materials will be available to take back to the classroom. Educators will receive comprehensive, objective information about the scientific concepts of energy and its importance while discovering the world of oil and natural gas exploration and production. Energy4me is an energy educational public outreach programme that highlights how energy works in our everyday lives and promote information about career opportunities in petroleum engineering and the upstream professions. SPE’s Energy4me programme values the role teachers and energy professionals play in educating young people about the importance of energy.
Kazakhstan, once one of the 15 republics of the Soviet Union, has gained international prominence in the oil and gas scene. The country is a rising star in the oil and gas industry, with rich hydrocarbon reserves and several world-scale projects such as the Tengiz and Karachaganak field developments. With a burgeoning oil and gas industry, petroleum engineering and geology students are becoming more active in seeking out development and networking opportunities. Technical U. (KNTU) organized its third international youth forum on "Future Caspian Oil and Gas" in Almaty, Kazakhstan, during 15–16 April. Approximately 300 students attended from universities across Kazakhstan, Russia, Uzbekistan, and Kyrgyzstan.
Kazakhstan has a world class endowment of petroleum resources including some of the world’s most fascinating and challenging super giants. With a large base of mature assets and the development of the Kashagan field, it is a good time to look for resources that will drive and sustain production levels for future generations. The oil and gas industry has a history of building reserves through frontier exploration, near-field exploration, and building reserves in existing reservoirs, through better definition of the reservoir and application of advanced technologies. All of these opportunities are present in the Republic of Kazakhstan: there is the enigmatic deep carbonate resource which is the focus of the ambitious Eurasia project; the further definition and development of Kazakhstan’s supergiants which can make large additions to their proven reserves; opportunities for nearfield exploration building upon existing infrastructure; and a large base of older producing fields which can be sustained through improved/enhanced oil recovery and new business approaches. The effort to add reserves in all of these areas is key to bringing on future production over the short, medium and long term.
Se, Yegor (Chevron U.S.A. Inc) | Galimzhanov, Saken (Tengizchevroil) | Amangaliyev, Bolat (Tengizchevroil) | Aitzhanov, Abzal (Tengizchevroil) | Yechshanov, Ilyas (Tengizchevroil) | Iskakov, Elrad (Chevron U.S.A. Inc) | Ghomian, Yousef (Tengizchevroil) | Bopiyev, Chingiz (Tengizchevroil) | Wang, Haijing (Chevron U.S.A. Inc)
Sour gas injection (SGI) in the non-fracture platform area of the giant carbonate oil field, Tengiz, began in 2007. SGI project was proven to successfully maintain reservoir pressure in the platform area, add significant reserves, reduce sulfur production, and enable additional oil processing capacity at the crude processing facility. Despite the confirmed benefits, the gas breakthrough and increasing gas-oil ratio (GOR) trends in several SGI producers became a concern as the injection project matured. The preferential production from wells with lower GOR allowed higher total oil throughput, but also introduced production constrain on SGI wells with higher GOR. As the result, SGI producers were historically choked back or completely shut-in as soon as the gas breakthrough was confirmed and the producing GOR began to increase above 500m3/m3.
The reservoir heterogeneity with the sour gas injection overprint created complex dynamic environment at the subsurface. Special surveillance program was designed to improve understanding of gas front movement through the reservoir, assess vertical and areal sweep efficiency and remaining oil in place in various zones of interest. Surveillance program design had to overcome several operational constrains, such as wellbore accessibility issues from the scale build, gas handling limits of the surface facilities, and complex simultaneous operations near the active high-pressure sour gas compressor. Moreover, the log interpretation had to consider crossflow and stimulation chemicals impact on the logging measurements. Finally, the integration of logging interpretation results with reservoir model was required to improve the reservoir model forecast and boost the value of acquired information.
This paper describes the results of the conducted surveillance campaign, the novel calibration methodology of gas saturation profile from the time-lapse cased hole measurements with proxy from the multi-component simulation model output and the early results of the performed gas shut-off operations. The described methodology allowed direct calibration of the model outputs with the gas saturation results from pulse neutron logs and provided more accurate sweep efficiency and oil recovery forecast across the entire SGI area. Calibrated model revealed consistent gas breakthrough profile and significant volume of low GOR oil remaining in the wells with gas breakthrough.
The updated reservoir model was then used to evaluate various development scenarios of SGI area. Gas shut-off scenario showed particularly encouraging low GOR production trends and improved oil recovery especially from the lower intervals. After the economic analysis, several wells, including long-term shut-ins, were added to the workover queue to timely realize production benefits. Early production results after gas shut-off workover consistently met or exceeded model forecasts. Described methodology provided more accurate scope definition, value assessment and justification for the SGI optimization project and could be applicable to other improved oil recovery projects.
A. H. Khan, M. Faisal (Pakistan Petroleum Limited) | Abid, M. Faraz (Pakistan Petroleum Limited) | Fareed, Abdul (Pakistan Petroleum Limited) | Javed, Zeeshan (Pakistan Petroleum Limited) | Khan, M Noman (Pakistan Petroleum Limited) | Hashmi, Shariq (Pakistan Petroleum Limited)
Technical evaluation and subsequently devising an appraisal and development strategy of a structural cum stratigraphic reservoir based on a discovery well only is always challenging. The reservoir under discussion was discovered as a structurally bounded trap and the appraisal wells were drilled on NW-SE direction along with the main bounding fault based on this understanding. However, presence of hydrocarbon below the spill point, anomalous sand thickness, lateral facies and reservoir quality variations observed in few of the wells indicated stratigraphic component in the field. Further complexity was added when the deepest tested gas was assigned on the structural map which showed extension of the hydrocarbon play outside the block boundary where the area was under different operating company that later drilled multiple wells near the block boundary. Therefore, it was critical to estimate correct initial gas in-place and percentage distribution of hydrocarbon across the lease boundaries.
Well location map for the studied field
Well location map for the studied field
The objective of this paper is to present workflow that integrates multiple dataset to understand the field's hydrocarbon filling mechanism. Detailed geophysical and Petrophysical work has been carried out, which includes building of sequence stratigraphic framework, preparation of seismic attribute maps, understanding of the depositional setting for all the individual sand units encountered in all the wells, rock quality assessment (core and log methods with integration of capillary pressure curves), free water level (FWL) assessment, permeability modelling using machine learning approach (NN), pore throat radius estimation to relate hydrocarbon filling mechanism and saturation-height function modelling to build consistent 1D water saturation model.
Comprehensive dataset has been acquired to evaluate the potential of the field that covers 3D seismic for the entire field, biostratigraphic analysis for seven (7) well, conventional logs in twelve (12) wells and advance measurements like Elemental Capture Spectroscopy and high-resolution resistivity images in five (5) wells. Core analysis data also acquired in five (5) different wells including routine core analysis, capillary pressure measurements using high pressure mercury injections, pore throat radius, relative permeability measurements (Centrifuge), formation resistivity factor measurements and sedimentological analysis (XRD & thin section) to overcome the challenges and defining the uncertainty associated with initial gas in-place.
Sequence based boundaries were defined to correlate individual sand bodies using the core data, image logs, elastic logs, seismic transacts and attribute maps for understanding the depositional setting. Lat-er these correlations were used to build a consistent petrophysical model including VCL estimation from Gamma/Neutron-Density/Sonic Density methods which was validated with ECS/XRD data. Porosity model was developed and validated from the core porosity followed by variable "m" estimation from the porosity/m relationship using the SCAL data. Later on, the consistent water saturation (Sw) models were built for all the studied wells. Permeability models were built using Neural Network (NN) where core-based permeability used for calibration and the model was tested qualitatively with the mobility and the well test permeability. For the validation of Sw from the logs, capillary pressure-based flow units were built using FZI/RQI, Winland & BVW (log) methods to define flow units defined through the core data. It was observed that the Winland R35 method-based pore throat radius had good correlation with the Sw log. FWL from MDT to estimate the height of the gas column, Skelt Harrison equation to capture the shape of the capillary pressure curve and Swi from the Centrifuge analysis were used to calibrate MICP end point which helped in building consistent Saturation-height functions. Results showed good to excellent match from the modeled Sw (Pc) vs Sw(log).
This paper presents the background, implementation, and initial results of a pilot project to address the shortage of qualified petroleum engineers in developing countries. Oil and gas talent gap in emerging markets was identified as an eminent problem by the Steering Committee of the World Economic Forum's (WEF) Oil & Gas Community in 2017. Chevron, Eni, and Shell acted on the initiative of WEF and, with the addition of Colorado School of Mines (Mines) as the academic partner, kicked off a pilot project to improve the Petroleum Engineering (PE) program at Satbayev University (SU) in Almaty, Kazakhstan, in 2018. The WEF working group, consisting of the representatives of the three companies and the department heads of Mines and SU, identified three priority areas: (1) Establishment of an Industry-Advisory Board (IAB) to promote mutual trust and collaboration between academia and industry, (2) Curriculum revision and improvement of the course material and delivery with the support of Mines, and (3) Student and faculty internship programs to provide industry training and support for faculty development. Many challenges of the Kazakh PE education are common to the other emerging oil and gas producing countries also. Therefore, the lessons learned from this project will be useful to develop similar projects not only in Kazakhstan but also around the world. This paper presents the details of implementation, challenges encountered, and initial results of the project.
Albertini, Cristian (Eni Spa) | Bigoni, Francesco (Eni Spa) | Francesconi, Arrigo (Eni Spa) | Lazzeri, Riccardo (Eni Spa) | Vercellino, Alberto (Eni Spa) | Borromeo, Ornella (Eni Spa) | Gabellone, Tatyana (Eni Spa) | Consonni, Alberto (Eni Spa) | Geloni, Claudio (Eni Spa)
The reservoir quality of Karachaganak Carbonates Field results significantly affected by diagenetic processes. In particular, the replacive dolomitization affects porosity, permeability and irreducible water saturation while the precipitation of anhydrite reduces both porosity and permeability. Such impacting processes were therefore analysed and described in the reservoir 3D Model following geologically consistent rules that honour well data.
The field scale diagenetic study was performed following five steps:
Core data studies Lithological logs analysis Hydrological processes identification Hydrological processes reactive transport simulations 3D Lithological model building
Core data studies
Lithological logs analysis
Hydrological processes identification
Hydrological processes reactive transport simulations
3D Lithological model building
The dolomite distribution, estimated from the lithological log analysis and cores data, results mainly confined on the flanks of the paleo-high. This distribution was endorsed by the results of 3D field scale reactive transport modelling related to Kohout geothermal convection mechanism acting in the shallow burial of the carbonate paleo-high at each stratigraphic unit. The final lithological 3D Model was built consistently with this hydrological process calibrated with well data used as verification data set in the stochastic simulations.
The anhydrite distribution, estimated from lithological log analysis and cores data, is, generally, present in a few percentage of volume and, mainly, in the upper section of the reservoir (less than 250 m, below the bottom of the overlaying Kungurian evaporites). This anhydrite was related to diffuse downward percolation of the Kungurian brine and, marginally, to dolomitization. The occurrence of higher concentration of anhydrite was also locally observed but generally connected to fracture infill and, sometimes, also in the deeper section of the reservoir. These events were related to brine percolation exploiting a network of syn-depositional fractures, particularly along the flanks of the carbonate bank (Neptunian dykes). Such hydrological processes was endorsed by 2D reactive transport modelling. In fact, the anhydrite infilling fractures may have a significant impact on the reservoir flow path and therefore a workflow for identification of these Neptunian dykes was applied, based on seismic attributes (Continuity and Curvatures) according to the Eni proprietary workflow utilized for the identification of sub-seismic discontinuities (Tfrac-Sibilla).
The so estimated dolomite distribution represents about the 15% of the lithology at field scale but up to the 60% on the flanks of the carbonate build-up, marginal areas investigated by very few wells but impacting on about the 30% of the field total GBV. Accordingly, the petrophysical characteristics of the field flanks result affected, in the 3D Reservoir Model, by the presence of dolomite, i.e. increased porosity, permeability and irreducible water saturation. Moreover, the identification of the sub-seismic discontinuities filled by anhydrite allows a better description of the permeability baffles affecting the 3D model flow paths.
This year, as part of the Opening Ceremony, SPE brings you two panel sessions that will focus on the conference theme “Co-operating Towards a More Competitive Environment to Encourage Investment Projects.” The panels will represent two different perspectives—the investors and operators in the region. Digitalisation is emerging as a technological driver of change around the world and is transforming how companies in the oil and gas industry operate. A wave of digital technologies and initiatives are leading this new era of innovation and opportunity. Investments in programmes such as analytics, data science, artificial intelligence, cloud computing, and other emerging technologies are being pursued to improve safety, reliability, and efficiency with the expectation of delivering significant value through improved processes and systems.
Differential compaction is an inherent process in carbonate systems that is thought to produce early natural fractures prior to any significant burial. Such fractures can persist and can be major permeability pathways, including areas of minor tectonic overprint. We forward model differential compaction fracturing in a carbonate reservoir in effort to predict the location of fractures in the subsurface.
3D finite-element geomechanical models are created to simulate differential compaction fracturing at a carbonate platform scale (kilometers) and the smaller carbonate build-up scale (10s of meters) commonly present within carbonate platforms. Interpreted seismic surfaces of key reservoir horizons are used as an input for the platform-scale model. Geometry of carbonate build-up from an outcrop analog is used for the build-up scale models. In both type of models layers identified to be compaction prone are restored to their expected pre-compaction state. A simplified mechanical stratigraphy scheme is adopted to distribute mechanical properties within the models consistent with their expected pre-burial properties.
Geomechanical modeling in this study was applied to a field which includes two carbonate platforms at different stratigraphic levels. Modeling results predict increased fracture intensity at the windward margin of the carbonate platform. This coincides with increased windward-leeward asymmetry of an underlying older platform. Increased fracture intensity is predicted at the center of the platform where the underlying older platform displays significantly less asymmetry. Predicted fracture locations over the platform top also correspond with the location of carbonate build-ups identified from seismic data. Fracture observations from image logs and indirectly from mud loss data within the upper platform are consistent with our modeling results. Predicted areas of greatest fracture intensity correspond with the location of wells with the highest fracture intensity observed from image logs.
Build-up scale models suggest that the build-up shape exerts a major control on the resulting differential compaction fracture pattern. Elongate build-ups tend to produce fractures oriented parallel to their axes. Circular build-ups tends to produce radial fracture patterns. Fracture orientation from image logs along with build-up shape observed using the coherence seismic attribute are consistent with these findings.
This study offers a process-based fracture modeling approach that can enhance the predictability of the location and orientations of natural fractures in carbonate reservoirs.