bluuebunny/crossref_metadata_2025 huggingface dataset:
Coupling Reservoir and Well Completion Simulators for Intelligent Multi-Lateral Wells: Part 1
Authors: Carvajal G. A. , Saldierna N. , Querales M. , Thornton K. , Loiza J.
Published: June 2013

To maximize well productivity and reservoir oil recovery in mature fields, advanced lateral designs with intelligent completions have been implemented during the last decade. The technology has been broadly applied, but how to effectively include its impact in reservoir well modeling is still being studied and developed. This paper describes an all-in-one system that combines nodal analysis and numerical simulation models to calculate the effect of intelligent completion components—such as swell packers, internal control valves (ICV), and inflow control devices (ICD)—on lateral production profiles.

In complex and high heterogeneity reservoirs, single wells are economically unsustainable in the long term because of many factors, including reservoir properties, early water/gas breakthrough, and non-selective-layer flow control or preference flow zones. The use of multi-lateral wells (ML) enables maximum reservoir contact while different zones are produced at the same time. Moreover, for those cases in which reservoir pressure and heterogeneity between completions are significantly different, downhole devices can control early water breakthrough and provide hydro-dynamic equilibrium in more than one lateral.

In this work, we used a 3D grid, multiphase flow and non-isothermal reservoir numerical simulator for advanced well design, and a wellbore nodal analysis simulator that numerically solves the partial differential equations between porous medium and the wellbore. When modeling the effect of any completion (ICD, ICV, and swell packers) on reservoir performance, the numerical simulator is coupled with a steady-state, network-based simulator that handles the completion effect inside the wellbore architecture.

This study is determining how to optimize the intelligent-completion design in a Middle East field to evaluate the completion efficiency and production performance over time. The new coupled approach—believed to be an industry first for multi-laterals—is being used to model openhole and ICD-ICV completions and production forecasting in a multi-layered formation associated with an active aquifer.
Uncertainty Quantification in Reservoir Performance for Field Test Evaluation Using Swarm Intelligence Algorithm
Authors: Okano H.
Published: June 2013

Production forecasts for petroleum reservoirs are essentially uncertain due to the lack of data. The unknown parameters are calibrated so that the simulated profile can match the observed data. This process is an inverse problem called history-matching which is ill-posed and may have non-unique solutions. This paper addresses two issues: 1) How can we calibrate physical properties in history-matching? 2) How can we predict uncertain reservoir performance based on history-matching?

The aim of our study is to quantify uncertainty of reservoir connectivity in a Turbidite sandstone reservoir. The target reservoir is in the on-shore oil field of which the depositional environment is a submarine fan of turbidite deposits. For the calibration we parameterise the reservoir properties and adopt a stochastic sampling method called Particle Swarm Optimisation (PSO) which is one of the swarm intelligence algorithms. Then a Bayesian framework along with Markov Chain Monte Carlo (MCMC) and Neighbourhood Approximation in parameter space is used to calculate the posterior probability. The MCMC is used to overcome the numerical difficulties calculating the normalisation constant in Bayesian inference.

A Bayesian framework and PSO have been applied to the evaluation of CO2 injection test in the tight oil reservoir where the wells have been stimulated by hydraulic fracturing. The observed data used for history-matching include the bottom-hole flowing pressure at the injector well and the gas composition at the wellhead of the producer wells. The in-place volumes and connectivity between the wells have been calibrated in a simple model using the effective algorithm of PSO. The calibrated parameters include permeabilities and porosities in the fracture cells, the length of the injector hydraulic fracture, the net-to-gross ratios and the horizontal and vertical permeabilities around one of the producer wells.

We showed the best fit model for the gas breakthrough and the P10-90 envelopes in the reservoir performance forecast assuming an on-going injection after the actual pilot test. The uncertainty envelopes in the CO2 mole fraction in the produced gas were estimated to see a gas breakthrough at each of the producer wells. The probability given production history is calculated from the prior belief and the misfit between the observed data and the simulated profiles, because the likelihood function can be calculated from the misfit. Our results contribute to the evaluation of the pilot test for a continuous CO2 injection in the tight oil reservoir.

The simplification in parameterising the very heterogeneous reservoir was the key to generating multiple history-matched models, because the amount of computation is prohibitive. It is much quicker to adjust large-scale heterogeneity in a simple model than in a detailed model. The simple model calibration with PSO and the forecast of Bayesian inference have been successfully applied to a real field data.
Clipper South Field: Fracturing Operations and Production Matching in a Low Permeability, Sandstone Gas Reservoir in the North Sea
Authors: Shaoul Josef , Park Jason , Bakhtiyarov Albert , Fekkai Sofiane , Jeffs Paul , Mandiwall Darrell
Published: June 2013

In order to produce economically viable wells from the Clipper South field, a low permeability gas reservoir in the UK Southern North Sea gas basin, the field was planned to be developed with horizontal, multiple hydraulically fractured wells. Clipper South is a Rotliegend dry gas field, comprising a mix of aeolian, fluvial and sandy sabkha sediments. The field is located approximated 100 km due east of the Theddlethorpe gas terminal in 23.5 m water depth. Reservoir is at 8,200 ft TVDSS, with average porosity 7 % and permeability ranging across the field from 80 μD to 100 μD in the core area. Initial temperature and pressure are 170 °F and 3,900 psi respectively. The field was discovered by well 48/19a-3 in 1983 and appraised by an additional well in 1992; well tests showed minimal flow from perforated intervals pre-fraccing. Given the poor reservoir quality, to sufficiently capture the reserves, development of the field requires five high angle wells with multiple hydraulic fractures in each well.

When drilling the first well unexpected reservoir complexity was encountered; no natural fracture network was seen in appraisal wells but C1 encountered sizable natural fractures and multiple high permeability streaks when drilling with significant gas peaks and associated mud losses. The natural fracture network influenced placement and necessitated alterations to fracture designs compared to planned dimensions. No dedicated stimulation vessel was available for the Clipper South development; a new-build supply-vessel was converted for use by installation of a large capacity frac spread which successfully pumped 8 frac-jobs along a 6,000 ft horizontal reservoir section. Stimulation was completed by the end of June 2012 and the well was brought online August, achieving above target post-stimulation flow rates.

This paper discusses how diagnostic data was incorporated into fraccing designs to produce a successful well; in particular logging data acquisition and pre-frac diagnostic tests, and how multiple injection tests were used to gain information on permeability along the wellbore to aid future reservoir modelling. Challenges encountered during stimulation operations and their implication for fracturing future wells will be discussed, along with methods for stimulation optimization and lessons learned. A summary will be given of the post-frac production analysis using a 3D reservoir simulation model with explicit Modelling of the eight propped fractures.
Building a Simulation Grid for Large Scale Reservoir Simulation
Authors: Al-Saadoon Omar , Hayder M. Ehtesham , Baddourah Majdi
Published: June 2013

Large scale reservoir simulation is essential to understand various flow processes inside the reservoir. With the advent of high performance computing (HPC), it is now possible to simulate models larger than even one billion cells. Because of its cost effectiveness, Linux clusters are very popular for large scale reservoir simulations. Many large clusters have been built by connecting processors via state-of-the-art high speed networks like Infiniband (IB), which can add considerable cost for the hardware. It is possible to connect multiple computer clusters to build a simulation grid, to simulate giant models, which may be difficult to do on a single cluster because of the size limitation. The network connecting clusters should be capable of supporting the needed data transfer rate to avoid performance degradation. Communication and computational load in a simulation depends on various parameters of the model, including size, underlying physics, mathematical formulation, etc. Our focus in this study is to examine HPC architectures, which may be used for large scale reservoir simulation in a cost-effective manner. Our design was made following extensive benchmark studies. We designed the network configuration, which is blocking in design to reduce the cost of hardware associated with the network. Our tests with large models indicate that there is only minor degradation in performance because of the new design, while significantly saving in hardware cost. We followed the Hyperscale design principle in constructing the cluster, eliminating all unnecessary components and keeping only essential ones. In this paper, we present results of our simulation grid and discuss scalability of such simulations. We also discuss benefits of a simulation grid in increasing utilization of hardware resources.
Integration of Production Facilities and Reservoir Simulation for Comparison of Subsea and Conventional Lift Technologies
Authors: Teixeira G. N. , Schiozer D. J.
Published: June 2013

Subsea processing has been considered a potential technology to anticipate and to increment oil production in deep water fields. The key element to achieve this is to increase pressure drawdown by reducing the backpressure imposed by the system. It can be defined as any treatment of the produced fluids performed on the seabed. Among the available technologies, Subsea Gas-Liquid Separation is the most advanced one for deep water applications. The most recommended way to estimate incremental oil recovery and to compare with other artificial lift technologies is through Integrated Production Modeling, which integrates reservoir, production and processing facility models.

The motivation of the present work is the need to quantify the incremental oil recovery achieved through subsea processing and the objective is to evaluate the possible advantages of using subsea gas-liquid separation as the main artificial lift method of a reservoir with similar characteristics observed in the recent discoveries in Brazil, comparing its performance with one of the most traditional lift technologies: gas lift.

The comparison is performed in two case studies. In the first one, a homogeneous reservoir model is used to focus the comparison in the artificial lift technologies. In the second case study, a heterogeneous reservoir model is used to evaluate the performance in a more realistic reservoir.

The results show that reservoir pressure maintenance is a key element to extract all benefits related to this subsea technology. A combination of technology (subsea gas-liquid separation and gas lift) also shows that it is possible to increment the oil production in a mature phase of the field. However, that it is not the same as changing the artificial lift technology. One of the benefits of subsea gas-liquid separation is that it is possible to produce the same oil quantity, compared to gas lift, with a smaller tubing and pipeline diameter.
Understanding the Impact of the Dynamic Environment When Acquiring Formation Pressures Whilst Drilling
Authors: Blanco Yon , Turner Marcus , Paul Scott , Benmansour Amel
Published: June 2013

In the last decade, Formation Pressure While Drilling (FPWD) measurement has developed from an emerging technology to a ubiquitous technology in environments ranging from ultra-deep water to land operations, as it is recognized for its cost efficiency and data quality when applied correctly. In addition to traditional uses similar to those of wireline-conveyed formation testers for reservoir evaluation, specific FPWD applications enabling real-time decision making in the well-construction process, such as drilling optimization and geo-steering, are now heavily utilized.

Many still argue that acquisition via wireline-conveyed methods produce higher quality data for reservoir evaluation, but to compare the measurements acquired by both technologies, it is necessary to understand the physics and dynamics in which both measurements are acquired. While typically the dynamic nature of FPWD data acquisition is seen to be disadvantageous because of mud circulating effects and potentially incomplete mudcake formation, operational practices during acquisition can mitigate these effects and particularly enhance test interpretation. There are unique opportunities for better understanding of test response and formation characteristics that are only available if the data are acquired early in the drilling phase. Complementing these measurements later with wireline data or even a subsequent FPWD pass while pulling out of the hole normally provides very valuable time-lapse information.

During this decade we have learnt that applying the same FPWD procedure for all environments might not obtain data of the highest possible quality because there are many variables to consider from the application to the environment. Formation types, mobilities, compaction, circulation rates, and mud types must be carefully considered during both planning and execution stages. In practice, we encounter reservoirs with variable permeabilities, different lithologies, and mud systems that are not always adequate. Lessons gathered from various environment types and innovative methods of acquiring data will be presented to address the following concerns: Formation damage and time-after-drilling implicationsAt-balance/underbalance conditionsStatic and dynamic superchargingTight and unconsolidated formations

The solutions developed through a decade of global experience and lessons learnt provide to new and existing users detailed insight into how to optimize procedures to deliver high quality data in many environments, whilst avoiding potential issues with the aim of acquiring pressure and mobility measurements as close as possible to a true representation of the formation under evaluation.
Assessing the Non-Uniqueness of the Well Test Interpretation Model Using Deconvolution
Authors: Cumming J. A. , Wooff D. A. , Whittle T. , Crossman R. J. , Gringarten A. C.
Published: June 2013

Uncertainty in well test analysis results from errors in pressure and rate measurements, from uncertainties in basic well and reservoir parameters; from the quality of the match with the interpretation model; and from the non-uniqueness of the interpretation model.

These various uncertainties, except the non-uniqueness of the interpretation model, were examined in SPE 113888. It was concluded that the permeability-product kh is generally known within 15%; the permeability k, within 20% (because of the uncertainty on the thickness h); and the skin effect S, within 8% for high S values and within ±0.5 for low S values. Distances (half-fracture lengths, horizontal well lengths, and distances to reservoir boundaries) are usually known within 25%.

The issue of non-uniqueness of the interpretation model is more complex: not only may there be a multitude of possible models for any one derivative response (the usual inverse problem), but there may be also a multitude of derivative responses, due to the uncertainty inherent in the observed data.

This paper presents a methodology for assessing the derivative response uncertainty using deconvolution. It is shown that the uncertainty depends mainly on the error bounds for initial pressure and flow rates, which yield a range of possible shapes for the deconvolved pressure derivative and therefore different possible interpretation models. In some cases, the non-uniqueness of deconvolution can be reduced using knowledge of the expected model response, for instance from geology or seismic. In the absence of differentiating information, however, alternative interpretation models have to be considered, which may lead to completely different development options.

The methodology is illustrated with three field examples.
Effect of Strong Preformed Particle Gel on Unswept Oil Zones/Areas During Conformance Control Treatments
Authors: Elsharafi Mahmoud O. , Bai Baojun
Published: June 2013

In oil industry, it is important to decrease water production and improve oil sweep efficiency. A newer trend in gel treatments is using preformed particle gel (PPG) to reduce fluid channels through super-high permeability streaks/fractures. The success of a PPG treatment depends primarily on whether or not PPG can selectively penetrate into highly permeable channels or fractures while minimizing penetration into lower permeable, unswept zones/areas. The purpose of this work was to determine what factors influence the damage of strong PPG on low-permeable, unswept zones. A filtration apparatus was designed to determine the possible penetration of PPG into low-permeable sandstone rocks. Filtration curves (the relationship between injection times vs. filtration volume) were obtained, and the permeability of sandstone cores, both before and after PPG treatment, was measured to determine whether or not PPGs reduce the permeability of low-permeable rocks. Daqing (DQ) gel was used as a PPG sample for our filtration experiments. DQ is a strong gel particle with an elastic module of ~6500 Pa at 1% of NaCl (wt%). The particle sizes of the gel ranged from 30 to 120 meshes. Filtration test results showed that 30–80 meshes of DQ did not impair the rocks with the permeability of of 3–25 mD. However, a powder of DQ gel with 100–120 meshes formed a cake on rock’s surface and reduced the core permeability up to 92.93 %. The damage of particle gel on unswept, low-permeable zones/areas was found to be effectively reduced by controlling both the particle size and the concentration of brine that was used to prepare swollen PPG.
Numerical Simulation of CO2 Storage Using the Vertical Equilibrium Approximation
Authors: Adeyinka Adeboye , Pickup Gillian , Olden Peter
Published: June 2013

When CO2 is injected into a saline aquifer for storage purposes, it rises through the brine to form a thin plume underneath a caprock (or under an intermediate shale layer). This is challenging to model, because a fine grid is necessary to resolve the plume and, since aquifers are extensive, many grid cells are required. On the other hand, simulations may be speeded up by using vertical equilibrium (VE) which assumes instantaneous separation of fluids due to gravity.

The focus of this work is to compare VE models with conventional black oil (BOS) and compositional simulations (CS) to determine conditions under which the VE approximation is valid. A simple 2D homogeneous pilot model was tested first. The base case model had 81×1×81 cells, and the refined models had 243×1×243 and 729×1×729 cells. Subsequently, a realistic 3D model representing the Bunter formation in the southern North Sea was used. This type of formation is expected to be used for CO2 storage in the future.

The results from the pilot model showed that the VE model could adequately represent the plume with a coarser grid than the BOS or CS models. For a homogeneous model, the VE approximation is therefore very useful. However, when applying VE to a heterogeneous 3D model, the results must be treated with caution. For the CS model, the areal distribution of the CO2 at the top of the aquifer showed that CO2 had migrated only through the high-permeability cells while the VE model showed evidence of CO2 migration through the high and moderate permeability cells.

The VE model saved processor time and gave reasonable results at low grid resolution. Even though the results may be less accurate for heterogeneous aquifers, the use of VE is important for the extended reservoir simulations needed to generate multiple realizations to capture the uncertainties and their effects on the aquifer-description parameters.
Modeling Net-to-gross in Deepwater Reservoirs
Authors: Chen Jiajie Jeff , Larson Todd
Published: June 2013

Use of Net-to-Gross (NTG) concept in reservoir modeling has been a debate as it involves choice of cutoff, a simplified representation of reality. In-place hydrocarbon volumes highly depend on the cutoff, thus some authors suggest avoiding use of this concept. However, when building a reservoir model, a process involving upscaling the well log curves to the reservoir grid resolution is often needed. This requires the investigators to account for the portion of an active cell that can allow fluid to flow. Thus, when carefully evaluated, the NTG method can be a necessary and acceptable approximation. From outcrop studies we also observe that no turbidite sequences have consisted of 100% net reservoir sands. The variations of net sand percentages depend on the vertical and lateral variations of strata that serve as the building bricks of the overall sequences. Several methods have been tested to model the NTG for various deepwater reservoirs in the Gulf of Mexico (GOM): Calibration of acoustic impedance (AI) curve into NTG from each individual well and propagating the NTG using stochastic method guided by seismically inverted AI and facies distributionScaling Gamma Ray (GR) or shale volume (VSH) curve to NTG by fixing the end members (sand and shale), scaling the curves linearly, and then conducting Sequential Gaussian Simulation to propagate NTG from wells to the reservoir modelUsing VSH cutoff to generate initial NTG for the wells, correlating the NTG with AI, and developing multi-relationships from the NTG-AI space to estimate NTG at the model scale. The multi-relationships serve as a tool for sensitivity test in the reservoir modelUsing total porosity frequency distribution from well logs to separate effective porosity for reservoir sands and un-effective porosity for non-reservoir rocks, then using porosity cutoff to distinguish sand from shale, and upscale the well log curves to model grid resolution to account for NTGEstimating NTG directly from whole cores

Using some case studies, we compared the difference of in-place volumes estimated based on different approaches. The studies show that as long as the assumptions for each method are physically sound, the NTG estimates are consistent. We conclude that the NTG of deepwater reservoir sands and their connectivity are the most important factors controlling total resource distribution and flow capability.
Reservoir Fluid Characterisation from Tests on Tight Formations
Authors: Moffatt Brian , Fawcett Michael , Maurera Jaimar , Bruzco Anna
Published: June 2013

Drill stem testing of low permeability reservoirs is challenging because high pressure drawdown around the wellbore readily lowers fluids below saturation pressure and creates two-phase flow into the wellbore. The fluids produced at surface no longer represent the original reservoir fluid. This paper shows the benefits of a careful methodology of data selection and equation of state (EOS) modeling to validate data used to characterize the reservoir fluid. Cases are examined where standard methods of capturing and characterising the reservoir fluid failed either because of sampling difficulties caused by two-phase flow within the reservoir. The first example is a lean gas condensate where there was a discrepancy between surface and bottom hole sample compositions. By an extended analysis of Gas: Oil ratio (GOR) over all the flow tests and taking a broader perspective of the welltest data, it was demonstrated the surface data were superior to the bottom hole samples. The second study is of a disguised volatile oil which had previously been classified as a rich gas-condensate based on welltest GOR. However, a review of the GOR versus rate and EOS modeling of reservoir saturation pressures gave a consistent indication that the native fluid was not a condensate but a volatile oil. In both examples the methodology of careful data selection followed by consistency of EOS modeling gave interpretations contrary to rule of thumb assumptions and revealed the true reservoir fluid compositions.
Extension of a Simple Model for Vertical Sweep in Foam SAG Displacements
Authors: de Velde Harsenhorst R. M. , Dharma A. S. , Andrianov A. , Rossen W. R.
Published: June 2013

Foam is a promising method to improve sweep in gas-injection enhanced-oil-recovery (EOR) projects. Where well-to-well distances are large, as in offshore applications, the question arises whether foam can prevent gravity segregation over large distances. For such cases, theoretical studies suggest that the best process is to inject one large slug of surfactant followed by one large slug of gas. Shan and Rossen (2004) present a simple model for such a process that provides an initial assessment whether foam can prevent segregation over large distances. They did not extend their calculations to the large distances between wells in some applications, and they treated only the case where vertical permeability kv equals horizontal permeability kh. Here we extend the model to cases of kv < kh. We derive an analytical solution for the limit as kv approaches zero, which could serve as quick first estimate of feasibility for other cases. Surprisingly, the model predicts that gravity segregation is worse as kv decreases; the reason is that with large kv foam pushes gas downward in response to the pressure difference across the titled foam front.

We illustrate use of the model with an example from a North Sea field, where the issue was whether foam could prevent gravity segregation over a distance of several km. The simple model said this was feasible, and more-detailed simulation then confirmed that segregation was insignificant over an inter-well distance of 6 km.
Time-Lapse Seismic and Engineering Data Integration to Estimate Best Time for Seismic Acquisition Data
Authors: Ferreira Carla J. , Schiozer Denis J.
Published: June 2013

4D seismic is important information to optimize well planning, interventions and drainage strategy. It provides unique information regarding the properties of the reservoir between and beyond the wells; it can be used to locate bypassed oil, to identify not drained compartments or to mitigate risks such as an unexpectedly early breakthrough of injected fluids. The integration of geophysics and engineering information increase the predictive capability of reservoir simulations, and hence has positive impacts on field management. The estimation of the best time to acquire seismic data has a major impact on reservoir management since, depending on the acquisition period, seismic may not be able to identify important variations in the reservoir dynamic properties, important changes may no longer be detected, well history matching can be able to identify properties, and it can be too late for effective action in field management. 4D seismic reservoir monitoring has no value unless it impacts operations and its utility is related to the period of seismic data acquisition. The challenge is to use effectively the available information; the integration of geophysics and engineering information must be accomplished by performing the history matching process that incorporates both production and 4D seismic data. Changes in saturation and pressure, derived from 4D seismic, can be used to improve the quality of the reservoir model allowing a better understanding of the reservoir model and fluid flow. Given the importance in defining the time for seismic data acquisition, this paper evaluates the quality improvement of a synthetic reservoir model by incorporating seismic data over different production periods and identifies characteristics that impact on the best time estimation. It also, estimates the best time to the case studied considering a practical condition. The study evaluated two cases: a posteriori (Case 1) and a priori (Case 2) analysis. In Case 1 the true model is known; a history match process was performed to 2, 4 and 6 years of production using two methods considering: (1) only production data; (2) production and seismic data. By analyzing the reservoir model quality improvement it was possible to identify the main characteristics that determine the moment to acquire seismic data. As, in practice, the earth true model is unknown, in Case 2, a process flow considering a risk analysis associated with reservoir simulation was applied to estimate the best time to acquire 4D seismic information. Analyzing the reservoir model quality improvement it was possible to identify the main characteristics that determine the best moment to acquire seismic data, to a non-mature oil reservoir with water injection production mechanism. These characteristics include: saturation and pressure error maps, production data error and breakthrough distribution within production wells.
Injection Testing: Gas Storage Field Experience
Authors: Azzarone Eleonora , Beretta Enzo , Marzorati Daniele
Published: June 2013

This work presents the interpretation of the injection testing operations performed on two wells in a gas storage field, located onshore Italy.

These field applications were aimed at setting the most suitable injection rates to allow the reintegration of the reservoir working gas. The injection gas rates were established as a function of the existing surface facilities constraints.

A secondary target was to confirm the areal hydraulic communication between two injection wells. A third well was used as an observation well to assess whether the hydraulic communication could be confirmed within the reservoir.

Two injection tests were conducted injecting methane gas into a depleted gas sands reservoir. All the wells were completed with sand control techniques.

The bottomhole pressure and temperature data were acquired by permanent downhole gauges allowing real time transmission. Memory gauges were used in the observation well to account for interference effects.

Over the sequence of several injection/fall off cycles, the downhole pressure response, observed in both the injection wells, was found to change and evolve over time.

In fact, during the injection history the expansion of the gas in the sand layer was able to displace the reservoir aquifer away. This effect was clearly experienced in the longest fall off phase.

Such a complex dynamic phenomenon can be properly described using 3D numerical simulators. However, a clear understanding was achieved utilising the standard analytical solutions typical of pressure transient analysis.
Simulation Sensitivity Study and Design Parameters Optimization of SAGD Process
Authors: Munoz Ricardo
Published: June 2013

The process of Steam Assisted Gravity Drainage or better known by its English acronym as SAGD has been successfully tested and commercially implemented in the last decade. It has been particularly successful exploiting the Athabasca oil sands in Alberta. Some of the reservoir features that are frequently present in the oil sands include the presence of bottom water, top water and gas caps. All of them, representing potential thief zones and are inherent to the reservoir nature.

Characterize and understand how those features affect the SAGD process is a key element of early project planning. In the present study, a simulation work to asses the feasibility of SAGD process for a typical section of the McMurray Formation in Alberta was conducted to asses the impact of the mentioned reservoir features.

This study confirms that the presence of bottom water is harmful to the SAGD process; thicker bottom water will be more detrimental. A vertical separation of 5 m to the bottom water was determined as optimum for the production well in order to achieve better recovery and economics. Depleted gas pools associated, or in partial communication with bitumen reservoirs represent a potential risk to the effectiveness of SAGD. The connectivity of gas pools to bitumen reservoirs depends on the vertical permeability and thickness of the material that lay in between; this determines their potential to prevent steam to escape up to depleted gas caps. An optimal range of inter-well spacing among 50 m and 80 m was established for the average reservoir conditions evaluated in this study.
Control of Reservoir Heterogeneity in SAGD Bitumen Processes
Authors: Stone Terry W. , Law David Hin-Sum , Bailey William J.
Published: June 2013

Uniform steam chamber growth (conformance) in a Steam Assisted Gravity Drainage (SAGD) process promotes enhanced bitumen recovery, project economics and environmental benefits. In the past, operators have implemented numerous alternative strategies to improve steam conformance in the SAGD process. Simultaneous injection in the inner tubing and annular space or use of dual-tubing completions are commonly used to provide some degree of injection control at the heel- and toe-regions of the horizontal well pair. However, this does not necessarily guarantee the uniformity and performance efficiencies sought. Distributed flow control devices (FCDs) can also contribute to more uniform production and injection. They can be incorporated in the horizontal production completion as restrictive elements to modify the pressure distribution along the length of the wellbore. A hybrid of these two technologies is proposed to provide superior (uniform and efficient) steam chamber development that benefits asset performance in highly heterogeneous bitumen reservoirs.

It has been shown that using Proportional-Integral-Derivative (PID) feedback to control the steam injection can be beneficial. The feedback control is applied to each steam injection point in the horizontal well pair. Injection at these control points is regulated by a PID feedback controller which monitors temperature differences between injected and produced fluids in order to both enforce a specified subcool and to achieve uniform production along the entire length of the producer.

This paper examines detailed wellbore simulations of a SAGD well pair with an FCD completion in the producer and PID controlled steam injection with dual tubing strings. A synthetic reservoir model, based on logs from the Athabasca region of Alberta, is employed and represents a highly heterogeneous formation with properties typical of a bitumen resource. Feedback controlled steam injection (FCSI) can be dynamically configured to target the worst-offending regions of the well pair in order to (i) start the PID control as early as possible after switchover, (ii) achieve a specified subcool target in those regions that would benefit most from the subcool and (iii) temporarily ignore regions which are bypassed and difficult to produce, but which may be dynamically included at a later time. Practical algorithms are presented to achieve these goals, based on existing technology.
Dielectric Properties of Synthetic Oil Sands
Authors: Swiech Weronika M. , Taylor Spencer E. , Zeng Huang
Published: June 2013

Dielectric logging tools have been used for some time in attempting to characterize oil reservoirs, and in particular to provide in-situ measurements of oil and water saturation. The particular sensitivity of basic electrical measurements, e.g. resistivity, to the presence of water made the original use of this approach most relevant to the determination of water-filled porosity.

In-depth dielectric spectroscopic analyses reveal contributions from underlying processes in materials, including electronic, ionic (electric double layer, EDL) and interfacial (Maxwell-Wagner, M-W) polarization, as well as molecular orientation. Our particular objective is the evaluation of dielectric spectroscopy as a means of characterizing the physico-chemical and structural characteristics of oil sands. Relatively recently, there has been a resurgence in interest in the application of dielectric techniques to unconsolidated heterogeneous systems. The present study builds on recent developments in the literature, and, specifically to determine the extent to which the potentially dominant effects of water can be overcome in order to access additional information, such as particle size and wettability.

This initial study has therefore involved investigating a range of synthetic oil sands systematically prepared from bitumen, water, sand and clay, to compare the behaviour with results obtained from a real core sample (obtained from a BP asset). The low-frequency dielectric spectroscopic analysis (10-2 to 107 Hz) yields complex properties (e.g. conductivity, permittivity, impedance) with frequency dependent in-phase and quadrature components. Within this frequency range, dielectric spectra are dominated by EDL and M-W polarization effects. By varying the sample preparation methods, it has been possible to observe structural differences with respect to water.
Phase Behavior and Viscosity Modeling of Athabasca Bitumen and Light Solvent Mixtures
Authors: Ghasemi M. , Whitson C. H.
Published: June 2013

This paper describes a systematic approach to model the phase behavior and viscosity of Athabasca bitumen and light- solvent mixtures for a wide range of temperatures. A cubic equation of state (EOS) is first developed using Athabasca crude assay data. We use a modified Jacoby correlation to describe the relationship of specific gravity and molecular weight for the bitumen sample. A gamma molar distribution model is used to fit the Athabasca crude assay data, then single-carbon-number (SCN) fractions are defined out to C90+. The Twu correlation is used for estimating SCN critical properties, including C90+, resulting in an EOS with 89 components (EOSSCN).

Pure solvent-crude oil mixture PVT data were tuned to the EOSSCN model by adjusting a fixed set of BIPs (binary interaction parameters) between pure solvent components (N2, CO, CO2, C1, C2) and all C7+ components.

For viscosity modeling, the LBC (Lorenz-Bray-Clark) correlation is used, with SCN critical volumes modified individually to ensure that the LBC correlation estimates SCN viscosities as given by a modified Twu correlation, based on specific gravity and normal boiling point.

The EOSSCN model was lumped into five pseudo-fractions (EOS5), the heaviest being C90+. The resulting model reproduces accurately all phase and volumetric behavior of pure-solvent-crude mixtures.

Initial viscosity prediction of the Athabasca crude by the EOSSCN/LBC and EOS5/LBC models is satisfactory for dead- bitumen with viscosity only affected by temperature. However, for viscosities of pure-solvent-saturated bitumen at varying temperatures, the EOS5/LBC model did not perform well. Our solution was to split the heaviest fraction C90+ into two sub- fractions, where only critical volumes differ, resulting in "lower-viscous" and "higher-viscous" C90+ fractions (C90+L into C90+H). The fraction of C90+L (fL) was found to correlate with pure solvent solubility and temperature, resulting in a quite- accurate overall viscosity fit. This final model has, in reality, six components, even though the two heaviest fractions are identical for EOS calculations – we call this final model EOS6/LBC.

The final EOS6/LBC model was checked against measured PVT and viscosity data for mixtures of the same Athabasca bitumen using synthetic combustion gas solvents made up of C1, CO2, and N2.
3.5D + 4D Seismic Reservoir Surveillance in Case of no Baseline Survey
Authors: Ling Yun , Guo Xiangyu , Cai Yintao , Guo Jianming
Published: June 2013

Before ninetieth last century the major oilfield in China was discovered using low fold large cell size 3D seismic or even 2D seismic acquired by the several hundred channel equipment. Obviously these kinds of seismic data could neither satisfy the needs of reservoir monitoring nor be used as the baseline survey of the time lapse seismic. The reservoir monitoring and remaining oil prediction for these oilfields thus becomes a difficult subject.
The Role of the Phase Behavior Model within the Numerical Simulation of in Situ Combustion Processes
Authors: Palma J. M. , Rodriguez E.
Published: June 2013

In situ combustion is a method with a large potential for recovery of heavy oil reserves, worse yet has many complexities that make it difficult its field scale development. One of these difficulties is precisely understand the different kinds of reactions taking place once the process starts. One tool that helps the engineer to understand what is happening during the process is the numerical simulation and specifically, for the case of combustion, the kinetic model. This model has two essential parts: the reactions and kinetic parameters. The reactions are developed based on the pseudocomponents used to characterize the fluid and the kinetic parameters were obtained from measurements made in the laboratory tests: Ramped temperature oxidation (RTO) and Accelerating Rate Calorimeter (ARC). The initial characterization of a fluid throws several components, which are subsequently lumped to the least amount possible without losing crude representation. These pseudocomponents must correctly represent the PVT behavior of oil. This matching to the actual behavior is achieved using suitable software. Based on the set of tests, it stars to match the behavior of the main fluid properties, for this, have previously chosen the most relevant parameters that may require matching to obtain a more representative model. Within the main tuning parameters are the critical properties of the fluid, accentric factors, lumping and splitting schemes and viscosity coefficients.

This paper proposes a scheme that helps to build a model that represents the phase behavior when the fluid is subjected to various conditions during the development of the combustion process. Matched the fluid model, this can be used in different scale models: CTO(Combustion Tube Tests), RTO or field. In this case, the successful development of the reactions involved in the kinetic model for in situ combustion process is linked the phase behavior model and the molecular weight of the pseudocomponents.
Using Geochemistry to Address H2S Production Risk due to Steam Injection in Oil Sands
Authors: Lamoureux-Var Violaine , Barroux Claire
Published: June 2013

Steam injection for enhanced oil recovery induces chemical reactions within the reservoir, called aquathermolysis, which can lead to in-situ H2S generation and to H2S production at the wellhead. H2S production risk is particularly acute in oil sand reservoirs because they contain sulfur-rich bitumens. To forecast H2S production risk in these conditions, a workflow based on geochemical investigation and reservoir simulation has been developed. It relies on (1) a quick estimate, using a dedicated technique, of sulfur content and thermal reactivity of a large number of reservoir samples to map the H2S production risk over the field; (2) carrying out more time-consuming aquathermolysis experiments on oil sand samples selected from step 1, to define a kinetic model for H2S generation based on atomic sulfur thermal reactivity; (3) transforming this sulfur-based kinetic model into a molecular SARA components-based kinetic model, usable in a compositional and thermal reservoir simulator; (4) simulating the EOR process with the reservoir simulator to calculate H2S/oil ratio at the wellhead.

The geochemical methodology has been applied to four oil sand samples from Athabasca. The results have underlined that sulfur content and sulfur thermal reactivity of oil sands measured with the quick estimation technique are well correlated with the amount of H2S produced from the more lengthy aquathermolysis experiments. Moreover, it was shown that the sulfur in the oil sand, when distributed among Saturates, Aromatics, Resins, Asphaltenes, Solid matrix and H2S, as a function of time and temperature of aquathermolysis, can be interpreted in terms of sulfur-based kinetic model. This model can be used for a calculation of H2S generation upon aquathermolysis at field production temperature and time scale, thus for estimating the H2S production potential.

As detailed in another SPE paper (Barroux et al., 2013), reservoir simulation has been used to simulate a SAGD process in a generic 2D model of an Athabasca oil sand. One main finding of this study has been that the H2S/oil ratio at the wellhead appears to depend mainly on the stoichiometry of the kinetic model.
Integral Study of the Influence of Well Trajectory on the SAGD Performance
Authors: Wu Yongbin , Jiang Youwei , Guan Wenlong , He Wanjun , Qiu Min , Lv Bolin
Published: June 2013

Due to various operational realities including the precision of the guiding tools that navigate the wells, actual SAGD well pairs in the field are seldom drilled perfectly parallel. And different patterns of trajectory of SAGD wellpair have a significant impact on the steam chamber development and overall recovery factor [1-4].

In this work, the focus is on the quantification of well trajectory on the SAGD performance. Based on the typical in-situ oil viscosities and reservoir properties of 11 SAGD pairs located in the Fengcheng heavy-oil region in Xinjiang Oilfield, different non-parallel patterns of injection-production-well-trajectory combinations including non-parallel vertically (upward inclination, downward inclination), horizontally and both directions between injector and producer well trajectories have been evaluated by using a detailed, 3D, flexible-wellbore reservoir-simulation model.

TTthe vertical and plane offsets in the horizontal segment both cause the smaller regional distance between injector and producer, resulting in better heat communication during preheating phase, while after converting to SAGD production phase, the better communication segment will cause faster steam chamber growth, leaving steam chamber in other segment developing poorly, therefore the SAGD peak oil rate and ultimate oil recovery factor are also affected. Especially, the case of plane and vertical offsets simultaneously cause the plane and vertical unparalleled, which causes the ultimate oil recovery factor 26.2% less than that of the ideal case without offset.