Zwaan, Marcel (Shell Intl. E&P Co.) | Hartmans, Rob (Petroleum Development Oman) | Schoofs, Stan (Shell Intl. E&P Co.) | De Zwart, Albert Hendrik (Shell Intl EP Co) | Rocco, Guillermo (Petroleum Development Oman) | Adawi, Rashid (PDO) | Saadi, Faisal (PDO) | Shuaili, Khalfan (PDO) | Lopez, Jorge L. (Shell Intl. E&P Co.) | Ita, joel (Shell Global Solutions International) | Lhomme, Tanguy Plerre Yves (Delft U. of Technology) | Sorop, Tibi (Shell) | Qiu, Yuan (Shell International B.V.) | van den Hoek, Paul (Shell) | Al Kindy, Fahad (Petroleum Development Oman) | Al-Busaidi, Said (Petroleum Development Oman) | Fraser, John Elliot (Petroleum Development Oman)
PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs.
However, the interpretation of this advanced surveillance data and integration into well and reservoir management workflows is still challenging. This paper describes the results of the integrated workflows for the interpretation, modeling and integration of surveillance data in four EOR projects. The surveillance methods include geomechanical modeling, thermal reservoir modeling and monitoring through time lapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging. This paper shows that the surveillance has contributed to the understanding of recovery mechanism in a pattern steam flood, it has supported decisions well-recompletions and work-overs and it has supported decisions on injection rates and surveillance planning in the chemical flood project.
Shaikh, Mohammed Razik (Petroleum Development Oman) | Rodriguez, Francisco Alberto (Petroleum Development Oman) | Reiser, Herbert (Shell Development Oman) | De Zwart, Albert Hendrik (Shell Intl EP Co) | Rocco, Guillermo (Petroleum Development Oman) | Al-Shuaili, Khalid Said (Petroleum Development Oman) | Adawi, Rashid (PDO)
A field, located in south Oman, has a compact dome shaped structure with an oil column in excess of 200m. It produces highly viscous hydrocarbon from the fluvial Cambrian Haradh reservoir and represents an opportunity for Thermal EOR development. After an initial phase of steam injection, field data have shown that the response in the trial pattern is not homogeneous. In order to explain these observations a multidisciplinary effort has been undertaken to improve our understanding of the subsurface.
The information acquired in and around the injection area (an inverted 7-spot pattern), include connectivity trends from pressure data, temperature surveys, time lapse seismic, cores and well logs. After 20 months of steam injection a thermal response within the pattern is limited to only one producer well and two observation wells. The time-lapse seismic data is consistent with the field data observed from wells in the northern part of the pattern. The pressure data also indicate a predominant North-South connectivity trend within the pattern.
Four geological scenario models were built to test factors that may impact the understood distribution of temperature resulting from injection. The modelling workflow intends to assess the impact of 1) the internal structural dip and baffling lithologies within the Haradh Reservoir, 2) faulting within the Reservoir interval, 3) the Carboniferous Al Khlata immediately above the Haradh Reservoir and 4) the variation of Haradh Sandstone Facies and how these may impact fluid flow.
The models have been calibrated against historical data so as to ascertain if a given geological realization is a reasonable subsurface representation to reproduce the actual field production and pressure data. The results indicate that an individual scenario does not provide by itself an absolute explanation to the field observations to date. Instead, a combination of scenarios (fluvial facies and faulting) is considered to be a more feasible option to understand the field observations.
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.
De Zwart, Albert Hendrik (Shell Intl E&P Co) | van Batenburg, Diederik W. (Shell Exploration & Production) | Stoll, Martin (Shell E&P International Ltd) | Boerrigter, Paulus Maria (Shell Development Co.) | Harthy, Said (PDO)
In this work we consider model-based optimization of polymer flooding. The reservoir performance is optimized by finding for each injection well optimal values for control variables such as injection and production rates, polymer concentrations, and times when to switch from polymer to water injection (i.e. polymer grading). The same technique can also be applied to optimize other EOR processes such as for example designer water flooding, alkali-surfactant polymer (ASP) flooding and foam flooding. The optimization method that has been used relies on the adjoint implementation in our in-house reservoir simulator to efficiently calculate the gradients. The adjoint method enables the computation of gradients with respect to injection and production rates, injection compositions of each well and switching times of each well at the additional cost of approximately the computation time of a single reservoir simulation. The optimization method uses the adjoint-based gradients to estimate the values of all polymer injection control variables that maximize reservoir performance.
The optimization method is demonstrated on a full-field reservoir simulation model. The physics that is modeled includes polymer mixing, hydrodynamic acceleration of the polymer molecules and adsorption of the polymer to the rock. The example shows that the Net Present Value increases significantly as a result of the optimization, mainly due to increased oil production and decreased polymer injection. The obtained optimal control is physically interpreted, so that the learning points from the model-based optimization can be applied to the field and can be used to enhance the polymer flood.
Rocco, Guillermo (Petroleum Development of Oman) | Adawi, Rashid (PDO) | Al-Busaidi, Khalfan Hamoud (PDO) | Rodriguez, Francisco Alberto (Petroleum Development of Oman) | Al-Busaidi, Said (Petroleum Development of Oman) | Al Kindy, Fahad (Petroleum Development of Oman) | Al Maamari, Abdullah (Petroleum Development of Oman) | Kiyaschenko, Denis (Shell International E&P) | Mehta, Kurang (Shell International E&P) | Lopez, Jorge L. (Shell Intl E&P Co) | Zwaan, Marcel (Shell Intl E&P Co) | De Zwart, Albert Hendrik (Shell Intl E&P Co)
A steam flood re-development of a mature field in the South of Oman is well underway with the first pattern of steam injection active since late 2008. The areal surveillance programme designed by a joint effort between Petroleum Development Oman (PDO) and Shell International Exploration and Production (SIEP) includes the simultaneous recording of a variety of seismic methods of different resolution. The main purpose of the time-lapse work is to monitor the steam conformance and sweep efficiency as the steam is injected in this heavy oil reservoir over 1,000 m below surface. Key aspects of the data acquisition campaigns, state-of-the-art processing and timelapse interpretation will be discussed. The ultimate objective of the programme is to evaluate the effectiveness of the techniques used in order to select the most appropriate and economically viable reservoir surveillance tools for full field deployment.
IOR/EOR processes have moving fronts and require an accurate description at a scale much smaller than typical grid block sizes used in black-oil simulations. Furthermore, they may require extra uid components and phases, or thermal properties, or sometimes chemical reactions between components. However, simulation of these processes on a high resolution grid throughout the reservoir is still not practical with today's computing power. One solution is to start on a coarse grid that is dynamically adjusted to provide sufficient resolution where needed. The challenge in such an approach is in identifying where and when to adjust the grid. This paper presents a semi- implicit scheme, that allows for the evaluation of grid adaption criteria within a time step, and guarantees that grid refinements occur where the fronts have propagated at the end of each time step. No assumptions on front movement need to be made in advance. The scheme is robust and accurate, while still providing strict control on the number of blocks by minimizing the extent of refined zone(s). This is of particular importance for nested refinements as the number of blocks rapidly grows with each extra refinement level. The combined use of changes in properties in space and in time allows for the definition of criteria that always reliably position the refinements along the fronts. Application of this dynamic gridding approach in simulation models with water-flooding, chemical-flooding, gas injection, and in-situ combustion demonstrates that efficient nested dynamic gridding can be implemented in a general purpose simulator to provide sufficient physical and spatial detail in meaningful eld or pattern models for IOR/EOR. The key to fast and accurate dynamic gridding is the implicit evaluation of proper criteria for refining and coarsening.
High Pressure Air Injection (HPAI) is a potentially attractive enhanced recovery method for deep, high-pressure light oil reservoirs. The clear advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas is its availability at any location. Although, the process has successfully been applied in the Williston Basin for more than two decades, the potential risks associated with the presence of oxygen in air are a significant hurdle for implementation in other locations.
Thermal simulations that include combustion are required to quantify the incremental oil, the oxygen consumption and resulting oxygen distribution from the application of HPAI in a given field. Once such a simulation model is available, it can be used to optimize the injection strategy: strategies that have a good incremental recovery while reducing the amount of gas injected are key to a successful project. The injection rate is bounded by a technical lower limit and an economic upper limit: there is a minimum rate required to maintain the combustion and high rates require larger compressors that are more expensive.
This paper focuses on the optimization of the injection strategy for HPAI in a 3D model with realistic geological features. Numerical simulations with a thermal model that includes combustion were conducted for continuous versus alternating air injection. A critical assumption for alternating air injection in that the remaining oil spontaneously re-ignites.
This study shows that water alternating air injection has a great potential to improve HPAI projects: project life can be extended and incremental recovery is improved when compared with continuous air injection. In addition, the variation in distribution of oxygen between different cycles is presented. This also illustrates that the numerical model can be used as an oxygen management tool. The effects of alternating air injection are comparable to the effects of alternating gas injection: the saturation in the swept areas changes due to the alternating (re-) invasion of gas, oil and water.
This paper illustrates that modeling oxygen consumption is essential for the evaluation of potential risks and optimization of the HPAI process.
Brooks, David (Shell Intl. E&P Co.) | De Zwart, Albert Hendrik (Shell Intl. E&P Co.) | Bychkov, Andrey (Shell) | Azri, Nasser (Shell International EP) | Hern, Carolinne (Shell) | Al Ajmi, Widad (Petroleum Development Oman) | Mukmin, Mukmin (Petroleum Development Oman)
De Zwart, Albert Hendrik (Shell Intl E&P) | van Batenburg, Diederik W. (Shell E&P Co.) | Blom, Carl P.A. (Shell Intl E&P) | Tsolakidis, Argyrios (Shell Intl E&P) | Glandt, Carlos Alberto (Shell Intl. E&P BV) | Boerrigter, Paul (Shell International E&P)
High Pressure Air Injection (HPAI) is a potentially attractive enhanced oil recovery method for deep, high-pressure light oil reservoirs after waterflooding. The advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas, is its availability at any location. HPAI has been successfully applied in the Williston Basin for more than twenty years and is currently being considered by many operators for application in their assets.
Evaluation of the applicability of HPAI requires conducting laboratory experiments under reservoir temperature and pressure conditions to confirm crude auto-ignition and to assess the burn characteristics of the crude/reservoir rock system. The ensuing estimation of the potential incremental recovery from the application of HPAI in the reservoir under consideration requires fit-for-purpose numerical modeling. Typically, the flue gas generated in-situ by combustion leads to in an immiscible gas drive, where the stripping of volatile components is a key recovery mechanism. HPAI has therefore, in some instances, been modeled as an isothermal flue gas drive, employing an Equation of State (EOS) methodology. This approach, however, neglects combustion and its effects on both displacement and sweep. Furthermore, the EOS approach cannot predict if, and when, oxygen breakthrough at producers occurs. Combustion can be included in a limited fashion in simulations at the expense of extra computational time and complexity. In the available literature, combustion is taken generally into account under quite simplified conditions.
This paper addresses the role that combustion plays on the incremental recovery of HPAI. Numerical simulations were conducted in a 3D model with real geological features. In order to capture more realistically the physics of the combustion front, a reservoir simulator with dynamic gridding capabilities was used. Kinetic parameters were based on the combustion tube laboratory experiments. The impact of combustion on residual oil, sweep efficiency and predicted project lifetime is presented by comparing isothermal EOS-simulations and multi-component combustion runs.