bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Upscaling on 3-D Modelling of SAGD in a Meander Belt
Authors: Deschamps R. , Guy N. , Preux C. , Lerat O. 
Published: October 2011

Abstract
This work aims at assessing the impact of heterogeneities on heavy oil recovery through SAGD process by using numerical models of a reservoir analogue of meander belt. These models are obtained with different scales of upscaling of the geological model.
Meander belts consist of point bar deposits, characterized by a 3D complex internal architecture, with different scales of heterogeneities, which distribution is associated with the depositional processes.
Based on a 3D outcrop description of a meander belt analogue to the Canadian heavy-oil fields, the approach includes four steps: 1/ the construction of a reference static reservoir model based on a very fine description of the outcrops in terms of architecture and geological heterogeneities, 2/ upscaling of the grid at different scales using different methods in order to evaluate their impact on the heterogeneity distribution in the reservoir, 3/ reservoir SAGD simulations using horizontal well doublet (steam injector and producer) across the meander belt, to assess the impact of upscaling of heterogeneities effect and on heavy oil production.
The impact of heterogeneities on simulation results are evaluated for several upscaling stages. Results show that heterogeneity distribution has an impact on fluid flow at different stages of production. On the fine gridded model, small scale heterogeneities impact the steam chamber development and fluid flow in the wellbore vicinity at the beginning of the steam injection, whereas large scale heterogeneities strongly influence oil recovery during the whole recovery process and lower the efficiency of the reservoir drainage. On coarser grids, the effect of small scale heterogeneities can be smoothed, depending on the upscaling stage. The geomechanical effect is not taken into account in this work, the goal being to assess the impact of heterogeneities on oil recovery.
The performance of SAGD is clearly linked to the steam chamber development, which depends on the degree of heterogeneities present in the reservoir. The simulation workflow and the sensitivity study based on different upscaling methods contribute to better restore the heterogeneity distribution in the reservoir. The negative impact of these heterogeneities during the oil recovery must thus be quantified in order to monitor the thermal production at crucial periods of production.
The Use of Slotted Expandable Liners in Multizone Openhole Frac-Packs: A New Completion Concept
Authors: Mason David , Duhrkopf Don , Morgan Quentin , McGeoch Andrew , Jones Colin 
Published: October 2011

Abstract
Sand production is becoming increasingly problematic due to the exploitation of poorer quality reservoirs and depletion of existing reservoirs. Cased hole frac-packs (CHFP) combine reliable sand control with potential for high productivity, and have become the completion of choice in many provinces. However, CHFP completions manifest in limited flow entry area into the well. This may cause two problems; a loss of productivity and potential screen erosion.
In CHFP designs it is common to perforate the casing with high shot density big hole charges, but due to shot orientation and phasing, only a relatively few perforations connect with the fracture. Entire well production therefore originates from 4spf or less. Detailed modeling shows that this will not cause productivity impairment if the proppant pack is undamaged. Predicted skins for undamaged CHFP should be slightly negative, but field observations in one particular region show typical skins of 2 to 5, but with skins above 10 also reported. This tends to suggest that proppant permeability is being reduced in-situ.
By contrast, productivity of open hole frac-packs (OHFP) is significantly less impacted by proppant damage and they also greatly reduce screen erosion risk. The productivity enhancement is revealed through detailed inflow modeling and laboratory experiments.
However, it is difficult to engineer multi-zone OHFP completions, and wellbore stability issues complicate implementation. These limitations can be resolved by setting field-proven expandable completion liner (ECL) in the openhole section, prior to running the inner sand screen completion and frac-pack tools. Experiments on large scale samples show that ECL stabilizes the borehole. ECL slot geometry also results in 3-5 fold increase in fracture connection area compared to CHFP.
ECL technology can also be combined with a number of different zonal isolation packer technologies, such as expandable, mechanical, swell and combo packer designs, to segment zones. This gives ECL frac-packs (EFP) the functionality of a multi-zone CHFP, but mitigates productivity impairment through proppant plugging and also screen erosion risk. The EFP completion concept also removes a casing string and eliminates perforating, and so also reduces HSE risks. It also has the potential to accommodate larger screen sizes, slim well designs and to reach deeper targets. The EFP completion concept also relies on integration of existing technologies, while offering the potential for a step change in well performance.
Minimum Transport Velocity Models for Suspended Particles in Multiphase Flow Revisited
Authors: Bello K. O. , Oyeneyin M. B. , Oluyemi G. F. 
Published: October 2011

Abstract
Increasing trend in the transportation of unprocessed reservoir fluid from assets located in remote locations and the drive towards maximising existing facilities and optimising production has encouraged many deepwater operators in the use of long subsea tiebacks.
However, the main challenges associated with unprocessed multiphase fluid flow in long subsea pipelines relate to constantly changing patterns and the likelihood of the suspended particles to settle out of flow and deposit in the transfer pipeline causing partial or complete blockage. Flow pattern transition is therefore a critical factor that must be accounted for in any particle transport models. However, current particle transport models do not account for these critical factors; besides the experimental data on which these models were validated are limited. Therefore they are often unreliable when subjected to varying operating conditions.
In this paper preliminary minimum transport velocity (MTV) models developed for rolling and suspended particles under different flow patterns are presented. The concept of particle velocity profile provided the basis on which the models were developed. Further work is planned to acquire large experimental data for the purpose of validating these proposed models.
The problem has been largely attributed to insufficient flow velocity among other parameters required to keep the solids in suspension and prevent them from depositing in the pipe. Additional complexities are introduced because of different flow regimes that occur within the pipe flow depending on the gas and liquid flow rates.
The development of minimum transport velocity models for suspension and rolling based on the concept of particle velocity profiles is a significant breakthrough in particle transport in multiphase flow. This has the potential to solve problems of pipe & equipment sizing, risk of sand deposition & bed formation, elimination of costs of sand unloading, downtime and generally improve sand management strategies.
Brilliant Water Shut-off Application Bypassing Existing Fish: A Success Story at Angsi Field, Malaysia
Authors: Johan M. Alham , Jalil M. Izwan , Ghazalli Rohaizat , Razak M. Hairi 
Published: October 2011

Abstract
Angsi is one of the major fields for PETRONAS Carigali Sendirian Berhad. Located at offshore Terengganu in the Malay basin area, Angsi had become the top priority in terms of oil production. One of its oil producers, A-66L was idle since 2007 due to high water cut observed after few years of production. Due to its high inclination, their first attempt to perform water shut-off and additional perforation were decided to be conveyed by electric line tractor.
The job, planned to isolate the I-33 zone using a mechanical bridge plug conveyed by eline tractor, turned into a major failure when the plug is suspected to get stuck in hole. The incident happened during pulling out the tool after activating it and the decision made at that point of time was to cut the eline cable at surface and to temporarily suspend.
Fishing job using braided line was successfully done after that. A total of 4800 meters eline cable was successfully retrieved and left the well with the failed mechanical bridge plug which was set above the targeted zone to be isolated. The team had come out with a brilliant idea of shutting off the water out zone and successfully perforated the new zone of interest with a small clearance from the existing top of fish. The well is now producing about 400 bopd.
This paper will discuss in detail the complexity of the overall operation, well challenges, water shut off bypassing existing fish and the selection criteria of perforation techniques to accommodate the small clearance. The decision making process and well intervention equipment selection will also be highlighted throughout the overall job operations.
A Dynamic Model for Simulation of Integrated Reservoir, Well and Pipeline System
Authors: Sagen Jan , Østenstad Monica , Hu Bin , Henanger Kjell Eirik , Lien Siv Kari , Xu Zhenggang , Groland Steinar , Sira Terje 
Published: October 2011

Abstract
Most reservoir simulations use vertical flow performance (VFP) tables to represent flow in the tubing, which ignores the flow dynamics in wells and their downstream gathering and transportation networks. On the other hand, most dynamic well-pipeline flow models use pressure-rate equations to describe the inflow/injection from/to the reservoir, which ignores the flow and pressure transients in the near-wellbore regions. Obviously, neither of the two types of modeling can account for the transient reservoir-well/pipeline flow interactions that can be of great importance in many operation scenarios.
To bridge this modeling gap, a joint industry program (JIP) was initiated based on a previous successful investigation [1] on the feasibility to implicitly couple a reservoir model to a dynamic well-pipeline multiphase flow model. The aim of the JIP was to deliver a simulation tool that can fulfill the industry's basic requirements on the modeling of transient flow interactions across the sandface, which should also lay the foundation for its future expansion in functionalities. This paper is intended to summarize the outcomes of the JIP.
First of all, the paper discusses the need for integrated dynamic modeling and reviews earlier efforts on building integrated dynamic reservoir-well/pipeline systems. Secondly the paper describes the details of building the reservoir model and how to couple it to a well-pipeline flow model to assure numerical stability and simulation speed for cases of interest. Thirdly, the paper shows the PVT and fluid handling options the integrated simulation tool can provide. These are identical for the two models in order to keep the consistence of fluid properties particularly when the same fluid flows back-and-forth between the wellbore and the near-wellbore during transients.
Two application cases based on the resulting model are presented in the paper. One case is about simulation of chemical squeezement hydraulics for refining the operational procedure, and the other case is about quantification of the pressure gradient in the near-wellbore formation for different well bean-up procedures in order to prevent sand production. The two cases demonstrate the advantages of using the coupled wellbore-reservoir transient modeling.
Impact of Supercritical CO2 Injection on Petrophysical and Rock Mechanics Properties of Chalk: An Experimental Study on Chalk from South Arne Field, North Sea
Authors: Alam Mohammad Monzurul , Hjuler Morten Leth , Christensen Helle Foged , Fabricius Ida Lykke 
Published: October 2011

Abstract
Changes in chalk due to EOR by injecting supercritical CO2 (CO2-EOR) can ideally be predicted by applying geophysical methods designed from laboratory-determined petrophysical and rock mechanics properties. A series of petrophysical and rock mechanics tests were performed on Ekofisk Formation and Tor Formation chalk of the South Arne field to reveal the changes in petrophysical and rock mechanics properties of chalk due to the injection of CO2 at supercritical state. An increase in porosity and decrease in specific surface was observed due to injection of supercritical CO2. This indicates that a reaction between CO2 enriched water and particles takes place which smoothens the particle surface. Accordingly, partial increase in permeability was also noticed. An effect is also observed from the decrease in pore-space stiffness, calculated from sonic velocity. No significant effect on wettability as indicated by NMR T2 relaxation time was observed. Rock mechanics testing indicates that in 30% porosity chalk from the South Arne field, injection of supercritical CO2 has no significant effect on shear strength and compaction properties, while there is probably a slight decrease in stiffness properties. For both the Tor Formation and Ekofisk Formation, flooding with CO2 after waterflooding does not seem to affect the shear strength parameters. For the Tor Formation, the elastic deformation parameters seem to be reduced after CO2 injection. In contrast, the effect on the elastic moduli in Ekofisk Formation is insignificant. The time dependent properties for both Tor Formation and Ekofisk Formation do not seem to be affected by CO2 flooding in the relevant stress regime. Generally, the change in both petrophysical and rock-mechanics properties is insignificant in Ekofisk Formation, compared to the changes in Tor Formation, most probably due to the very little contact cement in Ekofisk Formation chalk. Time-lapse monitoring strategies may be required during a CO2-EOR process for the measurement of changes in reservoir properties that may cause deformation of and leakage from a reservoir. Results of this study will provide data for designing future monitoring strategies based on 4D seismic.
Unconventional Type Curves: Useful, or Sirens of Destruction?
Authors: Haskett William J. 
Published: October 2011

Abstract
Considerable faith is placed in Type Curves; Type Curves that are ultimately responsible for resource estimation, revenue generation, and value determination. We assume that they are valid representations of what will happen, but is this faith warranted?
In and of itself, a type curve is a purely deterministic forecast of a multi-dimensional uncertainty. To their credit, explorationists have recognized range-based volumetric assessments as providing significant advantage in both resource determination and downside risk mitigation for nearly two decades. Given that nearly two-thirds of the uncertainty in NPV for an unconventional opportunity is production profile based, it is vital to understand the true range in the production profile. Unfortunately, given the two dimensional aspect (both rate and time are uncertainties) of time series uncertainty and the scale up issue from individual well ranges, this is not as straightforward as it may seem.
Attempts at ranged type curves tend to be biased by center anchoring and unreliable P10-P90 estimates. Ranged type curves are often the "expected" curve factored up and down symmetrically (!). This typically does not reflect valid production behavior. Well life is often inappropriately anchored at 40 years, or even 60 years and the curve is back-calculated to one of the most unreliable elements... initial production. The free variable in the calculation becomes decline, yet we receive decline information early in the life of the well. We have no clear reason to anchor production curves to a set time. As such, time should be the calculated variable. Additionally, the expected type curve when replicated across an area of potential will not be a representative case that delivers the expected value of an opportunity.
Type curves can be useful, ranged type curves even more so. Stochastic assessment of production potential allows companies to validly assess the true potential of a project area. It enables prioritized learning plans and downside recognition. Individual profile iterations can be easily ranked using discounted present production (DPP), but a value context is greatly preferred. Valid curves enable a company to recognize if a project will be production- or cost-sensitive and efficiently allocate time, people, and capital, thus optimizing the factory phase of the project.
Assessments are made to support decisions. Assessments without a decision context are a waste of time.
A New and Improved Approach for Geological Dependency Evaluation for Multiple-Prospect Exploration
Authors: Rasheva Svitlana , Bratvold Reidar B 
Published: October 2011

Abstract
Geological properties are likely to be shared for different prospects in a common basin. If, for example, source rock is found in one location, this increases the chance of finding it in other locations. Other geological characteristics will have similar correlation structures. When developing a drilling plan, these correlations should be considered because they can affect the optimal drilling sequence.
Modeling and accounting for these dependencies pose a significant challenge. The strength and structure of the dependencies must be assessed and specified through the use of conditional probabilities or correlations. Even for a relatively simple exploration plan, the resulting decision tree may have hundreds or even thousands of endpoints.
The sequential exploration problem with geological dependence has been addressed by several authors in the past few years. In this paper we extend this work by (1) simplifying the structure and model of the problem through the use of Influence Diagrams (Bayesian Decision Networks) and (2) using stochastic reservoir models to assess the dependence structure and strength. We also illustrate how to use the Maximum Entropy principle to construct joint probabilities when we have incomplete information about the correlation structure. Using Bayesian Decision Networks informed by stochastic reservoir models simplifies the modeling of exploration plans with a realistic number of wells.
Applying well known geostatistical techniques to aid in the assessment of the geological dependence structure and strength makes the approach more accessible to geoscientists wanting to account for these dependencies in their plans. Similarly, using Bayesian Decision Networks with their relatively simple and transparent structure will better facilitate the understanding and communication of the impacts of dependencies on the exploration plan. Given the typical exploration well cost, an optimal exploration program will in most cases generate significant savings.
Modeling SAGD with a Black-Oil Proxy
Authors: Ghasemi M. , Whitson C. H. 
Published: October 2011

Abstract
This paper describes a new approach to model steam-assisted gravity drainage (SAGD) using an isothermal black-oil (BO) reservoir simulator. The oil viscosity reduction caused by heating in the actual SAGD process is emulated by a tuned saturated pseudo-oil viscosity relation where solution gas-oil ratio (Rs) is used as an "equivalent temperature variable". In the black-oil formulation: (1) fully saturated oil viscosity (μo*) at reservoir pressure equals μo that would be attained at steam-chamber temperature (T*) in the actual SAGD process; (2) initial oil viscosity (μoi) with initial Rs=0, represents initial oil viscosity at reservoir temperature; and (3) black-oil gas properties represent steam at T*.
Upon careful analysis of the SAGD process, one finds that oil flows only along a narrow zone along the outer edge of the steam chamber – "edge oil-flow zone". The temperature gradient within this narrow zone is perpendicular to the oil flow direction and is practically impossible to model with any precision because of the large temperature variation and dynamic steam chamber shape over time. The black-oil model solubility gradient also varies, analogous to temperature in a thermal model, from zero to fully-saturated (Rs*) with an associated drop in oil viscosity from μoi to μo*.
SAGD design requires many hundreds of runs to find operational conditions that maximize economic value – e.g. injector and producer location, rates, pattern spacing, and steam chamber temperature T*. The proposed black-oil proxy model runs up to 10 times faster than a thermal model, while maintaining similar performance behavior.
The proxy model saturated pseudo-oil viscosity μo(p) relation used is found by history matching a full-physics thermal model performance prediction of oil rate, BHFP, and cumulative oil for a 2D homogeneous model. We have found a single-constant μo(p) equation that yields a good match to thermal SAGD performance. The tuned pseudo-oil viscosity relation honors the measured initial reservoir and fully-heated (at T*) oil viscosities. Its dependence on Rs is not physical, but reflects the use of Rs as a transform variable for temperature, capturing the strong spatial variation of temperature and oil viscosity within the localized steam-oil boundary region where oil has been mobilized.
The pseudo-oil viscosity relation, defined by a single empirical best-fit constant n – for a given T* and set of thermal properties – appears to be applicable for a wide range of reservoir heterogeneity, injection and production rates, and well placement. Consequently, it should be possible to use the black-oil proxy model for SAGD optimization of T*, control rates, and well placement, at a fraction of the CPU cost. We also see the potential of using the black-oil proxy model for solvent-based SAGD, with the pseudo-oil viscosity model depending on both T* and solvent; thermal compositional modeling is yet-even slower and less suitable for optimization.
EOS and Viscosity Modeling for Highly Undersaturated Gulf of Mexico Reservoir Fluids
Authors: Larsen Jarle , Sørensen Henrik , Yang Tao , Pedersen Karen Schou 
Published: October 2011

Abstract
PVT and viscosity data are presented for fluids from a deep and highly undersaturated Gulf of Mexico reservoir with a pressure of around 150 MPa. The fluid compressibility is a key property when evaluating the reserves and the potential recovery from such reservoirs. A common equation of state (EOS) model valid for 5 reservoir fluids is presented for use with the volume corrected SRK cubic equation of state. The compressibility at reservoir pressure is matched well and so is multi stage separator data. That makes the common EOS model applicable for reservoir simulation studies as well as for flow and process simulation studies. Simulation results obtained with the cubic equation of state are compared with results obtained with the PC-SAFT equation of state. High pressure viscosity data is presented and matched well with the corresponding states viscosity model using the same critical component properties as used with the common EOS model. It was possible to tune up the Lohrenz-Bray-Clark viscosity correlation to match viscosities ranging from 0.001 to 0.030 Pa s.