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.
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.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
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.
A case study on improving waterflood surveillance aided by a better understanding of the correlation between various water injectors and oil producers completed in the shallowest sub-layer of a giant multi-layered matured carbonate reservoir in Mumbai Offshore Basin is presented here. This understanding is then used to gauge effectiveness of the prolonged waterflood programme and to identify ‘target wells’ for optimizing water injection rate. The inferences of this analysis were tested using a simulation model.
Production, injection and pressure data of all wells completed in this sub-layer were extracted. The reservoir injection and withdrawal rates were computed using PVT data which were subsequently fed into an in-house developed streamline simulation program that generates a matrix of flow-based well rate allocation factors (WAF) correlating injection to withdrawal for each individual well as a part of its output. The analysis of injection efficiency per well was carried out in two scenarios viz. with current rates for effective waterflood surveillance and at a cumulative level with averaged rates to identify areas of deficiencies and optimize future injection rates.
Flow-based allocation factors provided a better picture than traditionally employed distance weighted technique owing to the underlying physics involved in describing streamline distribution in the reservoir. Results of analysis at the cumulative level indicated wells where injection efficiency, as measured by the ratio of injection rate to sum of streamlines-weighted withdrawal rates from connected producers, substantially deviates from 1. Few wells had an injector efficiency significantly higher than 1 which defined over-injection and potential recycling while a large number of injector wells had ratios of less than 1, highlighting the need to step-up injection rates and devise strategies for rigorous surveillance. To achieve the latter objective, injection-centric WAF's were regenerated at current situation with current rates and the dynamic nature of these factors could be observed by noting their slight difference with respect to previously estimated factors. This is attributed to averaged-out flow rates limiting the influence of newer high-rate producers and injectors. Nonetheless, wells in areas demanding attention are identified and requisite injection rates are assigned. These changes are included in the history-matched simulation model used for redevelopment activities and results were compared with a do-nothing case. The significant incremental recovery proves as a validation of the methodology adopted.
Waterflood surveillance on a well-to-well basis is always difficult in a matured field where water injectors are deployed in a ubiquitous fashion. This approach has rarely been employed in a reservoir of the size of Mumbai High and can be extended to other sub-layers subject to positive results from field implementation. Thus it is an endeavour to monitor waterflood effectiveness at a large field scale and could be beneficial for similarly developed fields.
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.
Skalinski, Mark (retired Chevron ETC) | Mallan, Robert (Chevron ETC) | Edwards, Mason (Chevron ETC) | Sun, Boqin (Chevron ETC) | Toumelin, Emmanuel (Chevron ETC) | Kelly, Grant (Chevron ETC) | Wushur, Hazaretali (Chevron ETC) | Sullivan, Michael (Chevron Canada Resources)
Assessment of the “net pay” is an essential part of reservoir characterization and resource determination. Standard methods usually involve the use of porosity, permeability and water saturation cutoffs to define net reservoir, net pay and perforation zones. However, there are no industry standards for the definition of cutoffs and their application in the reservoir characterization workflows. Assessment of net-pay cutoff s in carbonates is more challenging than in clastics due to inherent heterogeneity of pore architecture and permeability. Historically, the success rate of flowing perforations is low, and operators tend to “overperforate” to capture all potential flowing zones.
This study was undertaken to redefine pay categories and provide methods of cutoff determination in carbonates, leveraging applications of NMR logging, capillary pressure, and in-situ flow measurements. The new category of “gross hydrocarbon” is introduced to describe the rock charged with hydrocarbon. The new methods defining “gross hydrocarbon” are described: NMR shape analysis and hydrocarbon-charged pore-throat (HCPT) or R10 method. NMR T2 shape and 2D shape analyses define the minimum porosity and/or permeability with detectable hydrocarbon signal. The T2 shape analyses were performed for several carbonate fields around the world, yielding a porosity cutoff for hydrocarbon charge varying between 1.5 and 3.5%, depending on reservoir type.
The HCPT or R10 method used an extensive MICP dataset from these carbonate fields to predict an entry pore-throat radius corresponding to potential hydrocarbon charge. The predicted entry pore-throat log combined with the pore-throat size corresponding to capillary pressure at specific height above free-water level (HAFWL) allowed to define zones which were not penetrated by hydrocarbon charge due insufficient capillary pressure. Definition of those zones corroborated results from the NMR shape analysis. Both methods are restricted to hydrocarbon column.
The next cutoff investigated was the minimum value of permeability associated with observed flow of in-situ fluids indicated by wireline pressure test or production logs. This cutoff would correspond to the conventional “net reservoir” definition. The use of permeability mitigates the need for porosity cutoff s, which usually vary by rock type. The study performed in the different carbonate reservoirs yielded permeability cutoff s varying between 0.01and 1 mD.
Practical examples from Tengiz, Karachaganak, PZ, West Africa and Permian basin validate the consistency between methods and the validity of statistical predictions of R10 pore throat. The methods presented here can be applied to any conventional reservoir.
The present paper describes the results of analysis of depositional environment and tectonic setting within Karaton-Tengiz uplift zone in the southeastern part of the Pre-Caspian basin. The main purpose of the study is generalization and interpretation of geological and geophysical data for creation of stratigraphic charts and a description of lithological and tectonic processes for reconstruction of the structural history of pre-salt prospective traps located close to Tengiz field.
It is known that carbonates are "born, not made"; hence, their characteristics can give an insight into their depositional environment. The combination of such factors as availability of the light, warm climate, chemical composition and transparency of the water define the growth of the reef-building organisms. The highest carbonate production takes place close to the water surface; therefore, facies and texture of carbonates may be linked to the sea level changes. This means that understanding of the depositional environment and sequence stratigraphy may be used for a potential reservoir description where no well data is available. As a general understanding of the relative sea level fluctuations and its effect on carbonate growth, comparison of vertical thickness of studied platforms was carried out.
Analysis of regional seismic reflectors P3 (Top of Middle Devonian, tentative), P2D (Top of Upper Devonian), P2 (Top of Carboniferous), P1 (Top of Permian), VI (Kungurian salt deposits), V (surface of unconformity, Triassic), III (Top of Jurassic), II (Top of Lower Cretaceous) was also carried out for understanding of tectonic processes. Dipping of reflectors, thickness and depth variation of time-equivalent units, unconformities may indicate the change in tectonic setting. The shallowest depth of top of carbonates is observed on Tazhigali-Pustynnaya structure, gradually deepening towards Ansagan and Maksat to the south-southeast. Also, post-salt III and V reflective horizons are inclined from the north to the south of Karaton-Tengiz uplift zone.
Tectonic deepening in the south-southeast direction took place in several stages. The first stage, most probably, took place in Late Devonian–Early Carboniferous, as the result of which Ansagan and Maksat structures drowned. In the northern part of the Karaton-Tengiz uplift, the growth of reefs continued up to Late Carboniferous.
Well logging interpretation and published papers were integrated when possible. As the result, a conceptual model of the geological history and stratigraphic charts were created for the studied region.
Zhen, Wang (Research Institute of Petroleum Exploration and Development, PetroChina) | Junzhang, Zheng (Research Institute of Petroleum Exploration and Development, PetroChina) | Yankun, Wang (Research Institute of Petroleum Exploration and Development, PetroChina) | Jiquan, Yin (Research Institute of Petroleum Exploration and Development, PetroChina) | Man, Luo (Research Institute of Petroleum Exploration and Development, PetroChina) | Shuang, Liang (Research Institute of Petroleum Exploration and Development, PetroChina)
The "Two-Wide and One-High" (wideband, wide azimuth and high-density) Seismic Technique provided high-quality seismic data for more accurately identify the lithologic reservoirs, with low frequency information and broadband data being beneficial to the petroleum detection in the reservoirs. Hydrocarbon reservoir is a typical two-phase (solid and fluid phases) media. The seismic wave can display the characetristics of obvious low-frequency resonance and high-frequency attenuation in the seismic record after propagating through the two-phase media. Based on the theory and the "Two-Wide and One-High" Seismic data, the hydrocarbon detection is carried out in AMG block's two carboniferous sets of main reservoirs in the eastern Precaspian Basin. Three methods are useded to analyze variation in the lowfrequency and high-frequency after the seismic wave propagating through the exploration target strata, such as area difference method, time-frequency method of three primary colors method, instantaneous bandwidth method. The petroleum detection result accords well with the drilling testing data in the area, which means that this detection method based on the "Two-Wide and One-High" Seismic data could lower the exploration drilling risk and provides the advantageous basis for well location deployment of hydrocarbon reservoir exploration in the area.
Drilling the Taoudenni Basin located in Mauritania has posed a costly and time consuming challenge for operators trying to maximize profits in this challenging application. The formation compressive strength limits the bit selection to heavy set PDC bits or hard rock roller cone insert bits due to its abrasive composition. To help increase the effectiveness and drilling efficiency a hydraulically powered percussion drilling system was added.
As a proposed solution to a conventional drilling system, a new energy distribution system was introduced that would induce axial oscillations and percussion impacts while applying the same weight and torsional energy to the bit.
The system utilizes the torsional power of a conventional positive displacement motor combined with a high frequency axial pulse created with each rotation. The torque is transferred directly to the bit and 100% of the hydraulic flow is utilized through the bit nozzles. The mechanical lifting and failing action creates a rapid variation in weight on bit (WOB) allowing the bit’s depth of cut to fluctuate while overcoming different stresses. These variations, along with the percussion pulse created with each stroke, are what lead to increased rates of penetration.
This system was utilized on two wells in Mauritania drilling a variety of formations with both PDC and roller cone insert bits. This paper will focus on the 8 1/2” interval drilling the Jbeliat Teniagouri formation. This formation consists of sandstone, Shale interbeded with Siltstone, Dolerite and Pyrite. Confined compressive strengths range from 20 to 30kpsi in top section to 60kpsi in lower intervals when Dolerite appears. This new technology proved to increase ROP by more than 52% and interval drilled by over 100% through these intervals.