Many large wells have been drilled in the Gulf of Mexico's Lower Tertiary play. These wells are completed with single-trip multizone systems, and they have gross perforated lengths exceeding 1,500 ft. The main difficulty in perforating these wells is the high-pressure environment (~20,000 psi). Under these conditions, the challenges are to create sufficiently large entrance holes in the casing, minimize the high-risk of equipment damage due to gunshock, and minimize the amount of perforating debris created.
Perforating several intervals in a single run is required to complement single-trip multizone systems. Perforating all zones simultaneously in one trip saves time and reduces risks when compared with stacked completions requiring multiple trips for each zone. Safety and cost reduction are extremely important in deepwater operations. Risk control is very important because gunshock and/or debris problems can lead to multimillion dollar losses in non-productive time, and in extreme cases, gunshock problems can lead to lost wells.
To undertake these challenges, a new Low Perforating Shock and Debris (LPSD) gun system was used. In comparison with standard high-pressure guns, the LPSD gun system produces much less gunshock and negligible amounts of debris; thus, minimizing gunshock risk and reducing cleanup runs typically needed to recover perforating debris. LPSD guns produce negligible amounts of debris because LPSD guns contain all the metallic components, including the shaped charge cases, which remain virtually intact inside of the guns. A key element in planning these perforating jobs is gunshock prediction to evaluate if the equipment will be able to withstand the transient loads produced by the perforating guns. The gunshock prediction process is described in detail in this paper.
For a typical 4-zone 1,500 ft gross length perforating job, the time needed from picking up the first gun to laying out the last gun averages 84 hours. All zones are simultaneously perforated, which eliminates three perforating runs per well, saving approximately 9.2 days per well while minimizing personnel exposure. By perforating the largest high-pressure wells in the Gulf of Mexico's Lower-Tertiary play with LPSD guns, we minimized personnel exposure, minimized debris and reduced execution time up to 72%.
Masalmeh, Shehadeh K. (Shell Technology Oman) | Wei, Lingli (Shell International Exploration & Production B.V.) | Hillgartner, Heiko (Petroleum Development Oman) | Al-Mjeni, Rifaat (Shell) | Blom, Carl P.A. (Shell Intl E&P)
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.
Carbonate reservoirs contain more than 50% of world's remaining conventional hydrocarbon reserves and on average have relatively low recovery factors. With the insight that the era of "easy oil?? (conventional oil and natural gas that are relatively easy to extract) is phasing out, enhanced oil recovery (EOR) becomes increasingly important to maintain and extend the production plateaus from existing oil reservoirs. EOR technologies, however, require a refined understanding of reservoir heterogeneities and dynamic field performance. Simulation models for EOR studies need to have the right level of resolution and details. Often, we find that for a giant reservoir with a long waterflood history, working with full field models with coarse simulation grids is not adequate to understand the reservoir performance and calibrate the static model. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must.
Chen, Tianhong (Shell International Exploration and Production Inc.) | Noirot, Jean-Christophe (Shell Nigeria E&P Co. Ltd.) | Khandelwal, Arpit (Shell India Markets Private Ltd) | Xue, Guangri (Shell Oil Co.) | Barton, Mark (Shell Intl E&P) | Alpak, Faruk Omer (Shell Intl. E&P Co.)
Well test analysis in turbidite reservoirs is complicated by the intricate stratigraphy prevailing in this depositional environment. Because of this complexity, important reservoir architectural parameters driving flow behavior (e.g., shale drape coverage, object dimensions) cannot be estimated using simple analytical reservoir models employed in conventional well test analysis techniques. Alternatively, simulation-based well test analysis offers the advantage of being able to capture stratigraphic complexity. However, it requires a very large number of models and simulations to identify multiple solutions to such a highly non-unique inversion problem. In this work, we have developed a novel well test analysis workflow by constructing a large library of build-up type curves derived by appropriately scaling a comprehensive set of reference drawdown simulations. This set is used to rapidly identify a variety of stratigraphic scenarios matching a given well test. Key stratigraphic parameters are then estimated through statistical analysis of the results. The proposed well test analysis technique has been applied to synthetic and field examples. For the tested cases, stratigraphic interpretations derived from well tests are found to be consistent with those obtained from other data sources.
Warrlich, Georg Mathis (PDO) | Waili, Ibrahim Homood (Petroleum Development Oman) | Said, Dhiya Mustafa (PDO) | Diri, Mohammed (Petroleum Development Oman) | Al-Bulushi, Nabil Is-haq (Petroleum Development Oman) | Strauss, Jonathan Patrick (Petroleum Development Oman) | Al-Kindy, Mohammed Hilal (Petroleum Development Oman) | Hadhrami, Fahad (PDO) | Van Heel, Antoon Peter (Shell Intl EP Co) | Van Wunnik, John N.M. (Shell Intl E&P) | De Zwart, Albert Hendrik (Petroleum Development Oman) | Blom, Carl P.A. (Shell Development Co.) | Mjeni, Rifaat | Boerrigter, Paulus Maria
Petroleum Development Oman's (PDO) portfolio of heavy-oil, fractured carbonate prospects and fields contains a potentially large number of EOR opportunities, many of which present unique subsurface challenges. In the context of evaluating one such field, an EOR screening approach was developed combining subsurface definition through a tailor-made appraisal campaign, coupled with technical & economic feasibility evaluation of candidate EOR methods and benchmarking against other fields globally. This paper presents the screening workflow that will serve as template for the evaluation of future EOR opportunities in heavy-oil, fractured carbonate discoveries in PDO.
At the outset of the reservoir characterization of this field it was recognized that the application of any EOR technique would be challenging. High oil viscosities coupled with shallow depths render it a candidate for thermal EOR and potentially chemical concepts. However, key uncertainties in basic subsurface parameters such as reservoir architecture, matrix permeability, fracture spacing and (low) oil saturations, necessitated further data gathering before feasibility of any recovery mechanism could be concluded.
Based on literature surveys and examination of showstopper properties, a first-pass screening of a multitude of thermal and chemical EOR methods was conducted. A probabilistic assessment of key subsurface parameters was conducted against which the candidate EOR techniques were ranked. This resulted in the identification of SAGOGD, CSS, ISC and novel-chemical flooding as the most promising EOR methods.
For each of these methods the critical subsurface parameters and their impact were further assessed through the combination of (1) an appraisal campaign that included drilling of new wells, conventional production & pressure interference testing to constrain the uncertainties in these parameters and (2) Fit-for-purpose modeling (analytical analysis, sector modeling and full-field simulation) to check project feasibility.
It was found that none of the thermal recovery methods are technically or economically feasible, but chemical methods are being investigated further.
Valdez, Raul (Shell Intl E&P Co) | Jimenez, Jaime (Shell Intl E&P Co) | Adamson, Gary R. (Shell Intl E&P) | Agarwal, Binayak (Sabah Shell Petroleum Co Ltd) | Yeap, Yeow Chong (Petronas Carigali Sdn Bhd)
Gas injection, both Hydrocarbon Water Alternating Gas (HC WAG) and Carbon Dioxide (CO2) WAG, are possible Enhanced Oil Recovery (EOR) technologies to further develop and extend the field life of the Baram Delta Operations (BDO), located offshore Sarawak Malaysia. BDO consists of nine fields with an estimated STOIIP of about 4 BSTB. Over 100 reservoirs are in production within the cluster, with many wells operating as dual completions. The 6 largest fields in BDO have been on production for more than 30 years with an average recovery factor to date around 30%, mainly through natural depletion and aquifer support. Most of the fields contain light, undersaturated oil and after initial screening, gas injection is the most likely technology to extend the life of BDO and boost its recovery. The size, geological complexity of BDO, the number existing and aging offshore platforms and facilities; and then to design and execute a large scale, technically and economically optimal gas injection project, makes producing a fully integrated basin wide forecast challenging.
From a reservoir engineering perspective, simulation of miscible and near miscible gas injection requires compositional characterization and fine model gridding, compared with the size of reservoir, to be able to capture the physics (mass transfer, mixture properties and reduce numerical dispersion) to produce reliable results. Moreover, the economical assessment needs to have reliable estimates of incremental recovery, gas breakthrough times, gas utilization and gas recycling. Hence, small scale sector models rather than full field simulations are preferred so more robust results can be generated. The small scale model predictions, essentially building blocks, can then be scaled-up to generate full field forecasts.
Likewise, the implementation of a gas injection project requires an appropriate balance between enhancing oil recovery and facility constraints. The size and cost of facilities, the cost of gas supply, and the acceleration in oil production control the economic viability, and a good design comes from a balance between these variables. Consequently, there is the need to create multiple scenarios of how the gas injection will be managed not only for each reservoir and/or each field, but also the integration and timing of injection of neighboring fields. Rapid forecasting of dozens of reservoirs and 6 fields is required to adequately assess optimal staging and economical viability before selecting a final concept.
This paper presents the methodology used to build robust full field forecasts capturing key physics for the Baram Delta gas injection study. In addition to the methodology employed, a brief description will be given of the models developed and used as input into the full field forecasts, a brief description of the scale-up tool used, examples of forecasts developed will be shown and a summary of strengths and future enhancements.
Abu Bakar, Mohamad (Petronas Carigali Sdn Bhd) | Yeap, Yeow Chong (Petronas Carigali Sdn Bhd) | Nasir, Ernieza (Petronas) | Din, Azmi (Petronas Carigali Sdn Bhd) | Chai, Chon Fui (Sarawak Shell Berhad) | Adamson, Gary R. (Shell Intl E&P) | Agarwal, Binayak (Shell Technology india) | Valdez, Raul (Shell Intl E&P Co)
The Baram Delta Operations (BDO), located offshore Sarawak Malaysia, consists of 9 fields with an estimated STOIIP of about 4 BSTB. 6 of the major fields in BDO have been on production for more than 30 years. Average recovery factor to date is about 30%. EOR has been planned as an effort to boost the production as well as prolong the life of the field. A preliminary EOR screening study shows that water-alternating-gas (WAG) is the most amenable EOR process for BDO.
A PETRONAS and Shell joint study team was tasked to further extend the screening study conducted in 2005 by developing an EOR Big Picture for BDO. The objective of the study was to quantify the EOR potential in BDO and to develop a holistic areal implementation plan to mature the EOR potential. Scenarios evaluated involved a combination of three gas processes; immiscible hydrocarbon (HC) WAG as well as immiscible and miscible carbon dioxide (CO2) WAG.
All reservoirs in BDO were first screened and ranked. Eligible reservoirs were then characterized into a few groups according to fluid, rock type as well as aquifer and gas cap size. Optimized EOR performance was evaluated using full field models as well as smaller scale, detailed prototype models of a few selected reservoirs. The prototype models were developed using field analogue data which were representative of a particular reservoir group. The performance prediction of the remaining reservoirs not modeled was STOIIP scaling of representative dimensionless curves. The HC WAG reservoirs were all immiscible while the potential CO2 WAG was a combination of miscible and immiscible cases. The subsurface EOR evaluation also included an estimation of infill and water flood potential, associated well count, well cost as well as the net gas import required and the total gas handling required.
This paper presents the details of the systematic approach used to assess the subsurface EOR potential in the BDO fields.
Masalmeh, Shehadeh K. (Shell Technology Oman) | Blom, Carl P.A. (Shell Intl E&P) | Vermolen, Esther C.M. (Shell International Ltd.) | Bychkov, Andrey (Shell International Ltd.) | Wassing, L. Bart M. (Shell Intl E&P Co)
A new EOR scheme is proposed to improve sweep efficiency and oil recovery from heterogeneous mixed to oil-wet carbonate reservoirs. The reservoir under study is a highly heterogeneous and layered reservoir which can be described at a high level as consisting of two main bodies, i.e., an Upper zone and a Lower zone with a permeability contrast of up to a factor of 100.
The main recovery mechanism currently applied is water flooding. Field data shows that injected water tends to travel quickly through the Upper zone along the high permeability layers and bypasses the low permeable Lower zone, which results in poor sweep of the Lower zone. It has been demonstrated in earlier publications that this water override phenomenon is caused by capillary forces which act as a vertical barrier and counteract gravity for mixed or oil-wet reservoirs.
Polymer flooding has been proposed to improve sweep efficiency in heterogeneous reservoirs. In this paper we propose a new polymer based EOR option in which the water and polymer are injected simultaneously into the Lower and Upper zones, respectively. Injection of polymer into Upper zone serves to minimize cross-flow of injected water from the Lower zone and improves the sweep efficiency of both Upper and Lower zones. Compared to polymer injection alone, a much lower volume of polymer is required which has a significant positive impact on cost of this EOR process.
Numerical simulations have been performed using a history matched sector model. The model forecasts show that significant sweep improvement of the Lower zone is achieved compared to conventional water or gas injection. The results also show that the process is stable and robust to reservoir lateral and vertical heterogeneity, variation in polymer viscosity and that the amount of polymer that is used can be limited by only injecting a polymer slug of 0.1 to 0.2 pore volume. It is also shown that the process can be implemented in secondary and tertiary mode, where in tertiary mode earlier handling of production water is required. Experimental work shows there are promising polymers that may be able to withstand the high reservoir temperature, high salinity and high concentration of divalent ions in the reservoir under study.
In the past few years, we have been working on understanding waterflooding performance in heterogeneous oil-wet carbonate reservoirs (Masalmeh et. el., 2004, 2007b, 2008) with a focus on the impact of geological heterogeneity, imbibition capillary pressure and relative permeability models. In these earlier publications we have focused on parameters affecting cross flow between reservoir layers and hence sweep efficiency and field-wide remaining oil saturation distribution.
Operational reports indicate that a spike of H2S is sometimes evolved while flowing back the acidizing treatment. H2S is produced by the reactions between acid and sulfide scales. We investigate in this paper the performance of various H2S scavengers and deliver guidelines for field application of H2S scavengers in acid treatment of wells.
Five commercial H2S scavengers from chemical suppliers and service companies are evaluated under various conditions such as temperatures, acid-mineral ratios, and scavenger concentrations. Scavenger effects on reaction kinetics, acid dissolution capacity and scavenging capacity are investigated. Core flow tests, sequential spending tests, scavenger performance tests under field conditions, and compatibility tests were also performed to study scavenger effectiveness at various operation conditions and potential formation damage caused by spent scavengers.
In the tests reported here we identify one product that meets all our performance criteria, several that meet most performance criteria and several that meet few of our performance criteria for potential application to scavenge H2S in well acidizing fluids.
Reservoir flow simulation involves subdivision of the physical domain into a number of gridblocks. This is best accomplished with optimized grid point density and minimized number of gridblocks especially for coarse grid generation from a fine grid geological model.
In any coarse grid generation, proper distribution of grid points, which form basis of numerical gridblocks, is a challenging task. We show that this can be effectively achieved by generating a background grid that stores grid point spacing parameter.
Spacing (L) can be described by Poisson's equation ( ) where the local density of grid points is controlled by a variable source term (G). This source term can be based on different grid point density indicators such as permeability variations, fluid velocity or their combination e.g. vorticity, where they can be extracted from reference fine grid. Once background grid is generated, advancing front triangulation and then Delaunay tessellation are invoked to form the final (coarse) gridblocks. This algorithm is quite flexible, allowing choice of the gridding indicator and thus providing the possibility of comparing the grids generated with different indicators and selecting the best.
In this paper, the capabilities of approach in generation of unstructured coarse grids from fine geological models are illustrated using a highly heterogeneous test case. Flexibility of algorithm to gridding indicator is demonstrated using vorticity, permeability variation and velocity. Quality of the coarse grids is evaluated by comparing their two-phase flow simulation results to those of fine grid and uniform coarse grid. Results demonstrate the robustness and attractiveness of approach, as well as relative quality/performance of grids generated by using different indicators.
Practical handling of detailed geological models has long been a serious challenge for reservoir simulation and management. Efficient coarsening of the fine-scale model is a potential choice to alleviate the problem and has been addressed by several researchers. Original grids may be coarsened to generate structured or unstructured grids, each having pros and cons. As long as structured grid works well, it is preferable to unstructured one. However, when the physical domain is highly heterogeneous and geometrically complex, structured grids may fail to well capture the complex features, unless very fine grid is used. This contributes to the need for use of unstructured grid.
Unstructured grid generation (UGG) techniques generally entail three steps: grid point insertion, triangulation and construction of gridblocks. Insertion of grid points is completely arbitrary and is the main advantage of UGG. It is well understood that computational grid points have to be distributed in the physical domain in a way that these are denser where flow and rock properties are varying more or their magnitude are large. Thus areas such as near wells, high flow regions, fractures, faults etc are potential regions to be gridded finer. Several methods for the grid point insertion have been used in reservoir simulation. Local grid refinement (LGR) has been developed with this idea. Cartesian local grid refinement1,2 and hybrid local grid refinement3 are two well-known types of LGR. As these grids are based on a Cartesian grid, both have the difficulty in aligning the grid lines with complex features and boundaries. Modular gridding, proposed by Palagi and Aziz4, uniformly distribute the grid points in the domain, resulting in a coarse uniform Voronoi grid (base grid). Then several local grid systems suitable for specific geological and geometrical feature are constructed independently and placed in the appropriate location of that feature in the base grid. This procedure is able to generate flexible grids. However, it could only capture the notable features such as faults, large fractures, vertical and horizontal wells. It does not necessarily capture flow and rock heterogeneities.