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Results
Field Redevelopment Optimization to Unlock Reserves and Enhance Production
Al-Nabhani, Salim (Petroleum Development Oman) | Al-Marhoon, Nadhal (Petroleum Development Oman) | Al-Rubaiey, Faisal (Petroleum Development Oman) | Al-Kalbani, Ammar (Petroleum Development Oman) | Al-Mandhari, Badar (Petroleum Development Oman) | Al-Hattali, Ahmed (Petroleum Development Oman) | Al-Hashami, Ahmed (Petroleum Development Oman) | Hassan, Hany (Petroleum Development Oman)
Abstract A cluster area "H" consists of 4 carbonate gas fields producing dry gas from N-A reservoir in the Northern area of Oman. These fields are producing with different maturity levels since 1968. An FDP study was done in 2006 which proposed drilling of 7 additional vertical wells beside the already existing 5 wells to develop the reserves and enhance gas production from the fields. The FDP well planning was based on a seismic amplitude"QI" study that recommended drilling the areas with high amplitudes as an indication for gas presence, and it ignored the low amplitude areas even if it is structurally high. A follow up study was conducted in 2010 for"H" area fields using the same seismic data and the well data drilled post FDP. The new static and dynamic work revealed the wrong aspect of the 2006 QI study, and proved with evidence from well logs and production data that low seismic amplitudes in high structural areas have sweet spots of good reservoir quality rock. This has led to changing the old appraisal strategy and planning more wells in low amplitude areas with high structure and hence discovering new blocks that increased the reserves of the fields. Furthermore, water production in these fields started much earlier than FDP expectation. The subsurface team have integrated deeply with the operation team and started a project to find new solutions to handle the water production and enhance the gas rate. The subsurface team also started drilling horizontal wells in the fields to increase the UR, delay the water production and also reduce the wells total CAPEX by drilling less horizontal wells compared to many vertical as they have higher production and recovery. These subsurface and surface activities have successfully helped to stabilize and increase the production of"H" area cluster by developing more reserves and handling the water production.
- North America > United States > Texas (0.28)
- Asia > Middle East > Oman (0.26)
Structure and Hydrocarbon Prospects of the Russian Western Arctic Shelf
Stoupakova, A.V. (Moscow State University) | Kirykhina, T.A. (Moscow State University) | Suslova, A.A. (Moscow State University) | Kirykhina, N.M. (Moscow State University) | Sautkin, R.S. (Moscow State University) | Bordunov, S.I. (Moscow State University)
Abstract The Russian Western Arctic Basins cover the huge area including the Barentsand Kara seas, the western part of the Laptev sea and adjacent territories withsome archipelagoes and islands (Spitsbergen, Franz Josef Land, SevernayaZemlya, Novaya Zemlya, etc.). They comprise the Barents and Kara Basins, thenorthern areas of the Timan-Pechora Basin, the North West Siberia, includingYamal and Gidan peninsulas and the Yenisey-Khatanga Basin. Within the RussianWestern Arctic basins the following main tectonic elements can be identified:extensional depressions (Central-Barents, Yenisei-Khatanga, West Siberia, EastUrals) with sedimentary thickness is more than 12–14 km; platform massiveswith average thickness of sediments of 4 – 6 km, monoclines and tectonic steps, like transition zones between extensional depressions and platform massives. Western Arctic basins are filled by mainly Palaeozoic and Mesozoic sedimentarysuccessions. In the sedimentary cover of this large region, many commonstratigraphic complexes and unconformities can be traced within Palaeozoic andMesozoic complexes that show similarity of geological conditions of theirformation. Analysis of the Russian Western Arctic basins, their structures andhydrocarbon prosepctivity shows the areas, which are favourable for hydrocarbonaccumulations. Deep depressions, as areas of long-term and stable sinking, arehighly promising zones for the accumulation of predominantly gas fields. Theyform regional gas accumulation belts, extending for thousands of kilometres, where the largest fields can be expected in the zones of their intersectionwith the major tectonic elements of another strike. Within the Barents-Karashelf, the large belt of predominantly gas accumulation extends from the northof the West Siberian province through the South Kara basin and into the BarentsSea. The second potential belt of predominantly gas accumulation may beassociated with the North Barents ultra-deep depression. On the flanks of thedepressions the sedimentary cover profile does not contain the complete set ofoil-and-gas-bearing complexes, identified in the central parts of theextensional depressions. The reservoirs can be filled by HC due to the lateralmigration of fluids from the neighbouring kitchens or from their own dominantoil-and-gas source rock strata. For the formation of oil accumulations, themost favourable are platform massifs and ancient uplifts areas.
- North America (1.00)
- Europe > Russia > Barents Sea (1.00)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug (1.00)
- (3 more...)
- Phanerozoic > Mesozoic > Jurassic (1.00)
- Phanerozoic > Mesozoic > Triassic (0.70)
- Phanerozoic > Paleozoic > Devonian > Upper Devonian (0.69)
- (2 more...)
- Geology > Sedimentary Basin (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- (3 more...)
- Europe > Russia > Northwestern Federal District > Northwestern Federal District > Nenets Autonomous Okrug > Timan-Pechora Basin (0.99)
- Europe > Russia > Northwestern Federal District > Nenets Autonomous Okrug > Timan-Pechora Basin > Khoreiver Basin > Pomorskoye Field (0.99)
- Europe > Russia > Northwestern Federal District > Komi Republic > Nenets Autonomous Okrug > Timan-Pechora Basin (0.99)
- (46 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (0.94)
Abstract This paper presents the workflow and the results of integration of seismic, well and production data on Habban Field to optimize well locations. Habban Field is located in the Jurassic Marib-Al Jawf-Shabwah basin of Yemen (Block S2). Development targets in Habban Field are fractured Precambrian Basement, Kohlan and Shuqra formations (Middle Jurassic). Main challenges faced in the Field are Basement heterogeneity, fracture distribution and their connectivity, lateral variation of Kohlan Formation and the overlying salt diapirs/walls hampering the seismic imaging. The difference between a good and a dry well is whether it is encountering main fracture corridors or not. Fracture corridors (along the faults) have limited lateral extent and due to overlying salt diapirs well trajectory optimization is very challenging. Reflection pattern in the Basement is quite chaotic. Therefore, it was important to come up with a workflow to image faults within the Basement so that highly deviated to horizontal wells can be drilled to enhance production and optimize recovery. In order to address these challenges, wide azimuth 3D seismic was acquired and processed in different azimuths. The study has been conducted using 3D seismic dataset and derived seismic attributes combined with information from thirty one wells including image and production log interpretation. The workflow highlighted the value of G&G integration to better outline uncertainty and to mitigate risks during well locations and trajectory planning. In this contest structural attributes (i.e. AntTracking) have been crucial in order to define and identify the faults zones for optimizing horizontal wells targeting multiple fracture zones. On the other hand integration of G&G and production data highlights the limitation in defining a one-to-one correlation between seismic, well and production information mainly due to reservoir complexity and scale resolution.
- Phanerozoic > Cenozoic > Paleogene (0.94)
- Phanerozoic > Mesozoic > Jurassic > Upper Jurassic (0.68)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous (0.46)
- Geology > Structural Geology > Tectonics > Salt Tectonics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.88)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (1.00)
- Asia > Middle East > Yemen > Shabwah Governorate > Marib Shabwa Basin > Block S-2 > Habban Field (0.99)
- Asia > Middle East > Yemen > Qishn Formation (0.99)
- Asia > Turkmenistan > Caspian Sea > Cheleken Contract Area > Block 2 > Lam Field > Zone 7 Formation (0.98)
- (7 more...)
- Information Technology > Data Science (0.68)
- Information Technology > Artificial Intelligence (0.46)
Challenges in Developing Attic Oil under a Giant Gas Cap, Advances in Modelling and Completion Strategy, a Well Case
Xu, Siqing (Abu Dhabi Company for Onshore Oil Operations) | Kshada, Ali (Abu Dhabi Company for Onshore Oil Operations) | Mukhtar, Muhammad (Abu Dhabi Company for Onshore Oil Operations) | Abdou, Medhat (Abu Dhabi Company for Onshore Oil Operations) | Amiri, Abdel Hameed (Abu Dhabi Company for Onshore Oil Operations) | El Wazeer, Fathy (Abu Dhabi Company for Onshore Oil Operations)
Abstract The reservoir under consideration, Reservoir A of the Lower Cretaceous age, Kharaib formation is a complex giant carbonate reservoir within an onshore field in Abu Dhabi. Substantial volumes of oil remain to be developed from the Attic area directly underneath the giant gas cap. 4 Attic wells were drilled since 2005 and they have all experienced gas breakthrough. To better manage Attic well production and optimize attic development, one of the attic wells has been selected for a pilot to install Integral Control Valves (ICV). The aims and objectives are for down hole zonal gas production control leading to optimized single well recovery while respecting facilities gas handling constraints. In parallel, two long horizontal wells are being drilled next to the pilot well to test the alternative concept of low production drawdown for gas breakthrough control. This paper presents the design and detailed modelling study carried out for the ICV pilot well and the two long horizontal wells. The ICV pilot completion design is described. The technology include swellable packer, inflow control valve (ICV), fiber optic DTS (Distributed Temperature Sensing). The open hole will be segmented into 3 sections using fed through swellable packer technology to pass fiber optic lines and install one ICV gross each section. The overall aim is to enable well GOR control, reduce project cost, maximize production and minimize any future rig intervention cost of shutoff at specific section. A detailed single well model was developed within the 3D full field model. The well model was history matched, including PLTs and saturation logging. For ICV installation planning, a full range of sensitivity and uncertainty analysis was performed to assess likely impact. In particular, the impact due to potential faulting/sub-seismic faults was assessed. The model was also used to define data acquisition planning post ICV installation The early production performances from the ICV pilot well are presented. For the two long horizontal wells, well design considerations are presented. Plan for continued monitoring of the 3 wells are shown, with the aim of helping to optimize attic oil development.
- Europe (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.36)
- Asia > Middle East > Saudi Arabia > Thamama Group > Kharaib Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.97)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Developing High Resolution Static and Dynamic Models for Waterflood History Matching and EOR Evaluation of a Middle Eastern Carbonate Reservoir
Masalmeh, S. K. (Shell Technology Oman) | Wei, Lingli (Shell China Innovation and R&D) | Hillgartner, H.. (Shell Technology Oman) | Al-Mjeni, R.. (Shell Technology Oman) | Blom, C.. (Shell Technology Oman)
Abstract Enhanced oil recovery (EOR) has become increasingly important to maintain and extend the production plateaus of existing oil reservoirs. Simulation models for EOR studies require the right level of spatial resolution to capture reservoir heterogeneity. Data acquired from the dedicated observation wells are essential in defining the required resolution to capture reservoir heterogeneity. For giant reservoirs with long production history, their full field models usually have grid block sizes that are of similar scale as the distance between injectors and observation wells, with the consequence of losing the value of the time lapse saturation logs from dedicated observation wells. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must. The objective of this paper is to present an improved and integrated reservoir characterization, modelling and water and gas injection history matching procedure of a giant Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates geological, petrophysical, and dynamic data in order to understand the production history and the remaining oil saturation distribution in the reservoir. Large amounts of field data, including time lapse saturation logs from observation wells, have been collected over the last decades to provide insight into the sweep efficiency and flow paths of the injected water. Iterative simulations were performed to investigate different scenarios and various sensitivities with each iteration involving an update of the static model to honor both the dynamic and core/log data. While applying this iterative process it was also acknowledged that conventional core data (e.g. 1 plug per foot) may not capture the high permeability streaks in these heterogeneous reservoirs that control much of the reservoir flow behaviour, hence much denser plugging and core examination is required. In addition, permeability upscaling procedures need to take into account the fact that core plugs may not represent the effective permeability of the larger connected vuggy pore systems. The improved understanding of reservoir heterogeneity, the more robust reservoir characterization, and the improved history matching demonstrates that a better representation of reservoir dynamics is achieved. This provides a solid platform for designing and planning future EOR schemes.
- Europe (0.87)
- Asia > Middle East > UAE (0.28)
- North America > United States > Alaska (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Subsurface Uncertainty Assessment for a New Carbonate Field Development
Ouezzani, Mohammed Ridha (Abu Dhabi Marine Operating Co.) | Belery, Paul (Abu Dhabi Marine Operating Co.) | El-Kassawneh, Reyad (ADMA-OPCO) | Daify, Hossam (Abu Dhabi Marine Operating Co.) | Ishiyama, Tomohide (Abu Dhabi Marine Operating Co.) | Yoshida, Koichi (Inpex Corporation) | Zidan, Maher (Abu Dhabi Marine Operating Co.)
Abstract The objective of this paper is to present an integrated approach to quantify subsurface uncertainties and to share the assessments that have been applied in the subsurface studies of a new offshore oil field development in United Arab Emirates. A methodology was developed to review and rank the various subsurface uncertainties. Seismic and geological tools were used to assess uncertainties of static parameters, while integration of all uncertainties was made in the dynamic simulation model. New approaches were implemented to address two important parameters: Critical Water Saturation and Permeability. Critical Water Saturation uncertainty was derived by history matching production test data using a Saturation-Versus-Height model coupled with a Fractional Flow equation. For estimating uncertainty on Permeability, correlations with core derived fracture densities were developed. Uncertainty on the Critical Water Saturation was found to have the highest impact on oil recovery. This uncertainty is related to an observation already made for other carbonate reservoirs where perforated intervals are sometimes producing at very low water-cut in spite of high water saturations interpreted from the logs. This uncertainty review allowed updating the Dynamic Model with more robust P50 estimates of its parameters. The updated model was used to define a new base case development well scheme and production profile. The study was important in maturing the development studies further. It was used in particular not only for updating the Dynamic Model, but also for defining future studies, preparing a data acquisition plan, and identifying mitigation actions to reduce the subsurface risks.
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- (4 more...)
Challenges and Key Learning for Developing Tight Carbonate Reservoirs
George, Bovan K (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Clara, Cedric (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Al Mazrooei, Suhaila (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Manseur, Saadi (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Abdou, Medhat (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Chong, Tee Sin (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | Al Raeesi, Muna (Abu Dhabi Company for Onshore Oil Operations (ADCO))
Abstract Fast track development projects, with timely data acquisition plans for development optimization, are very challenging for tight and heterogeneous carbonate reservoirs. This paper presents the challenges and key learning from initial stages of reservoir development with limited available data. Focus of this study is several stacked carbonate reservoirs in a giant field located in onshore Abu Dhabi. These undeveloped lower cretaceous reservoirs consist of porous sediments inter-bedded with dense layers deposited in a near shore lagoonal environment. The average permeability of these reservoirs is in the range of 0.5-5 md. Mapping the static properties of these reservoirs is difficult since they are not resolved on seismic due to the low acoustic impedance contrast with adjacent dense layers. Petrophysical evaluation of thin porous bodies inter-bedded with dense layers in highly deviated wells pose significant challenges. Laterolog type LWD resistivity measurements which are less affected by environmental effects, offer more accurate formation resistivity compared to propagation type measurements. With limited suite of logs, some of the zones with complex lithology had to be evaluated innovatively as detailed in the paper. Integrated studies are initiated to improve reservoir description by carrying out accurate permeability mapping, SCAL, geomechanical and diagenesis & rock typing studies. Significant challenges exist regarding the development of thin, tight and highly heterogeneous reservoirs, in terms of recovery mechanism, well architecture, well count, drilling, well completion and economics. Static and dynamic models were used extensively to evaluate different development scenarios and conduct sensitivity studies to bracket uncertainties. Various geo-steering options were discussed and the paper also details maximizing the reservoir productivity using long reach MRC (Maximum Reservoir Contact) wells. Tight and heterogeneous reservoirs call for extensive and real time reservoir surveillance activities to assess well performance and reservoir connectivity. This paper highlights how these challenges are overcome through upfront surveillance planning and proactive well completion strategy.
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Lagoonal Environment (0.54)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.47)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government (0.46)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 149477, ’Investigation of Liquid Loading in Tight Horizontal Gas Wells With a Transient-Multiphase-Flow Simulator,’ by Donald F.B. Jackson, SPE, SPT Group, and Claudio J.J. Virues, SPE, and David Sask, SPE, Encana, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed. Liquid loading occurs in gas wells when production declines to a rate that is insufficient to lift the associated liquids to the surface. Liquid holdup in the horizontal section may impair production before liquid loading in the production tubing becomes evident. Holdup in the horizontal section can lead to slug flow at the tubing and to early onset of liquid loading in the tubing. The results from a transient-multiphase-flow model were found to be consistent with data acquired from video logging. Sensitivity analyses were performed with several normalized trajectories. Introduction Technology applied in conventional reservoirs in offshore horizontal wells can be applied successfully in onshore horizontal wells in unconventional reservoirs. The Jean Marie formation is an Upper Devonian carbonate platform between two thick shale layers in the Greater Sierra area, approximately 90 km east of Fort Nelson, British Columbia, Canada. The formation has low porosity (averaging 6%), low water saturation (averaging 20%), and low permeability (less than 1 md to air). Formation depth ranges from 600 to 1500 m subsea—1000- to 1900-m true vertical depth. The formation is entirely gas saturated with a dry sweet gas (95% methane) and is variably underpressured, with initial reservoir pressures of 6 to 15 MPa. The horizontal wells are drilled underbalanced to limit formation damage. Fig. 1 shows a typical well completion with 177.8-mm production casing set at the top of the Jean Marie formation. Gas is produced from the openhole portion of the completion. While drilling horizontally through the Jean Marie formation, the well trajectory is steered on the basis of gas-rate-while-drilling (RWD) data. The geologists maneuver up and down in inclination until a good permeability streak is indicated by a spike in flow rate from the RWD data. After reaching target depth, tubing (typically 60.3 mm) is installed and the well is brought on production. Typical gas- production rates for Jean Marie wells decline from an initial rate of 56×10 m/d to 14×10 m/d after 12 months and to 10×10 m/d after 36 months.
- Europe > Norway > Norwegian Sea (0.44)
- North America > Canada > British Columbia > Northern Rockies Regional Municipality > Fort Nelson (0.24)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.24)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract A rapidly-growing energy demand in recent years has made shale gas more attractive than ever. Although shale-gas formations contain a large amount of hydrocarbons, their low-permeability characteristics have been a major impediment to economic development of the fields. Once properly designed, foam fracturing has advantages over the conventional hydraulic fracturing – for example, by using less water, it works better for water-sensitive shale-gas reservoirs; a smaller quantity of water involved makes the fracturing job more environment-friendly due to the reduced amount of chemical additives; and it offers a superior capability to carry and distribute solid proppants over the newly-created factures. In spite of its unique advantages, optimum foam fracturing treatment requires a good understanding of foam rheology. A series of recent experimental studies revealed that foam flow can be represented by two distinct flow regimes in general: low-quality regime showing stable plug-flow pattern, and high-quality regime showing unstable slug-flow pattern. This study, for the first time, presents how to develop a comprehensive foam model that can handle a variety of bubble-size distributions and flow patterns by using two-flow-regime concept for fracturing. Analyzing experimental data of surfactant foams and polymer-added foams shows that (i) in the low-quality regime, foam rheology is governed by bubble slippage at the wall with no significant change in its fine foam texture and (ii) in the high-quality regime, foam rheology is governed by the relative size of free-gas segment to fine-textured foam-slug segment. By using these governing mechanisms, this new foam model successfully reproduces foam flow characteristics as observed in the experiments, including almost horizontal pressure contours in the low-quality regime and inclined pressure contours in the high-quality regimes. Although the model is built with a power-law fluid model, the same procedure can be taken for Bingham-plastic or yield-power-law fluids.
- North America > United States > Texas (1.00)
- North America > Canada (0.68)
- Research Report > New Finding (0.87)
- Research Report > Experimental Study (0.68)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (32 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract: The reservoir in the central part of the Alberta portion of the Deep Basin Montney Trend yields the promise of a resource play that may be as extensive, productive and rich in liquids as the best portion of the Eagle Ford Shale in southern Texas. Various geological and petro-physical parameters are compared, along with initial production signatures to show the similarities with the liquids rich, Eagle Ford analog. Liquid and gas analyses are recombined at various, observed, condensate/gas ratios and subsequently input into a compositional simulation model. The extreme representations of these fluid characterizations, varying from rich gas to volatile oil, can be used to achieve comparable history matches of producing wells. The reservoir fluid grades from a rich gas (50 Bbl/MMcf condensate) to a light crude system (3,350 scf/Bbl), from west to east, with a coincident rise in elevation of 100 m. There are no ‘traps" holding the fluid in place other than the very low permeability of the reservoir. Large flow potential gradients exist from the westerly, down-dip, gas rich portion of the reservoir, toward the easterly more liquids rich region. This dynamic liquid on top of gas situation is upside down relative to conventional trapped hydrocarbon deposits. It is the result of dissipation of hydrocarbons away from their point of source and the fact that the catagenesis process converts source materials preferentially to methane with increased depth and temperature. This situation is known to occur in a number of deep basin, over pressured, mixed hydrocarbon deposits in North America including the Montney, the Eagle Ford and the Utica. Reservoir modeling is complicated by the need to initialize a model with lower density fluid underlying more dense fluid and with large potential gradients through the hydrocarbon column. This study illustrates a method used to establish the initial, dynamic as to geologic time, state of fluid distribution. It goes on to illustrate why conventional means of characterizing reservoir fluids are inappropriate due to the nature of the reservoir fluid distribution and, possibly, misleading. Fluids sampled from a point source, be it from a surface location or the bottom of a horizontal well’s vertical section, is not representative of the phase distribution along the entire horizontal well lateral. The 2,430 meter long, Montney horizontal lateral, located at 9–12–64–4W6M, straddles a transition zone that penetrates myriad hydrocarbon phases and compositions, the aggregate of which cannot be represented by a single phase envelope. These types of wells could be classified as either "Gas" or "Oil" if using conventional criteria, depending upon which liquid/gas ratio was used to recombine fluids. The usual, conventional, methods of classifying should therefore be discontinued for wells producing from deep-basin, over-pressured, mixed-hydrocarbon-saturated reservoirs. Data from a detailed core analysis (61m core), and various re-combined fluid analyses, are used to achieve a history match of initial production data from the liquids rich Montney well producing within the Kakwa field. The compositional simulation model is used to run sensitivities on 1) liquid yields and corresponding re-combined reservoir fluid, 2) permeability modifications to the hydraulic fracture and stimulated reservoir volume (affecting fracture conductivity), and 3) quantities of reservoir gas that has migrated up-structure from the source, if necessary, to achieve comparable history matches. The quantity of gas migration is controlled by invoking a miscible flood, 200 years prior to the beginning of well production and varying the permeability within high permeability streaks, or "fractures", to essentially replicate gas migration from the high temperature source in this unconventional reservoir. The "injector" and "producer" used at either end of the reservoir structure, in this model, are used to facilitate the movement of relatively small amounts of gas. The model is initialized, for the purpose of history matching (and forecasting), with a model that not only has a "fingering" distribution of phases and compositions, within the transition zone, but also represents the varying pressure gradients observed along the reservoir dip. Up-dip the pressure gradient approaches 10.5 kPa/m while the down-structure end of this reservoir yields gradients that exceed 13.5 kPa/m. The ultimate purpose of this study is to show what geological conditions prevail within this particular area of the Montney play and why they make this the ideal location for liquids rich gas production. It will show how much detail is required (or not) to generate a representative forecast model or type curve. It will also attempt to quantify error bars associated with parameters typically defined for this purpose, particularly those related to the range of solution gas/oil ratios (or liquid yields) that generate comparable history matches. And finally, this study will show what impact the characterization of reservoir fluids may have on well spacing and reservoir development plans.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Petroleum Play Type > Unconventional Play (0.86)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.49)