bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integration of Production and Process Facility Models in a Single Simulation Tool
Authors: Morales Fernando L. , Velázquez Juan Cruz , Hernandez Aarón Garrido 
Published: December 2007

Abstract
Traditionally in the upstream business, operational decisions are made separately at the reservoir, production and surface facility levels, using only their respective knowledge, experience and engineering tools without limited coordination between them, sometimes bypassing important considerations from other components of the overall production system, outside of their specific domain. For example, a common practice in the oil industry is to generate a production forecast derived from a reservoir-based model, without taking into account surface facility constraints that could lead to unrealistic approximations. Restrictions in compression power or pump capacity, for example, could impose significant limitations over the well and surface network performance that could impact long term field management plans if they are not properly identified and solved.
PEMEX E&P San Manuel complex produces in excess of 276 mmscf/d and 13,100 BOPD from 10 fields (mostly gas and condensates, but also oil fields) through 69 wells using 6 process facilities and its corresponding pipeline network. Built more than 25 years ago, this PEMEX E&P facility, originally designed for much higher gas and liquid rates than the current ones, faced several slug and counter-pressure problems arising from over- and under-capacity of in its current surface infrastructure. This work describes how a team of reservoir, production and process engineers, developed and implemented a data, simulation and analysis workflow to identify the well-network-process system's major bottle necks and made recommendations of several low cost optimization alternatives to overcome them. The project's results of implemented recommendations increased production in excess of 2,000 BOPD, with no additional investment, and reduced the asset's operational cost by more than USD$ 600,000 USD a year. This simulation tool also proved to be very valuable for early identification of well optimization opportunities, strategic planning and informed decision making, considering the size of the full well-surface facility system.
Rapid and Low-Cost Methodology to Obtain an Updated Compositional Model of Produced Fluids Using Separator Discharge Data Analysis
Authors: Morales Fernando L. , Velázquez Juan Cruz , Hernandez Aaron Garrido 
Published: December 2007

Abstract
Fluid characterization data used to build representative reservoir fluid models for reservoir and production engineering is generally scarce and very costly, due to the expense of fluid sampling and analysis and, operational related problems of well intervention. The problem turns more dramatic when the field to be studied has been producing for some time and its bottom-hole pressure has reached the bubble point. In those cases, initial reservoir fluid data is more difficult to be used as some portion of the hydrocarbon's heaviest or lightest components, whether oil or gas is produced, may have been left in the reservoir and initial PVT data is no longer valid or very difficult to match to current fluid behavior.
One of the most common practices of obtaining fluid data is by taking well bottom-hole samples, or by obtaining surface oil and gas mixture samples and analyzing them in the lab using recombined methods. Due to the costs involved, including loss of time and production, operating companies do not obtain fluid data with the required frequency. Accordingly, engineers are left with the only option of using non-updated or insufficient data that will affect the outcome of their simulation studies.
This work describes a rapid and low cost methodology to obtain an updated compositional model for produced fluids using gas chromatography, oil characterization and GOR from analysis of the separator fluid discharge. The required samples are easily collected with low cost to the operating company.
Then, a case history is shown where compositional fluid models obtained with the proposed method are used in well, surface network and process facility simulation models, with excellent results. A comparison of field data against the simulation model results is also shown.
A Dynamic Wellbore Modeling for Sinusoidal Horizontal Well Performance with High Water Cut
Authors: Tang Yula , Wolff Martin , Condon Patrick , Ogden Katharine 
Published: December 2007

Abstract
The Banzala Field (Block 0, Angola) has produced oil with horizontal wells and ESP's as the artificial lift method for more than seven years. These wells were drilled with large sinusoidal undulations intentionally to cut the pay section a number of times. Banzala "A" horizontal wells underperformed expected production, possibly due to downhole slugging. In addition, declining reservoir pressures, rising GOR, and rising water-cut have also adversely affected production.
The objective of this simulation study of wellbore transient flow is to understand past production performance and to find ways to mitigate adverse well behavior. Simulation showed that low ESP efficiency could be related to down-hole slugging. GOR was the most significant factor for slugging and increasing water cut made slugging worse. The sinusoidal wellbore trajectory was studied to optimize ESP operating conditions. It was found that reducing sinusoidal amplitude by half and flattening the heel-end entrance angle from 79 deg. to 86 deg. would suppress slugging significantly.
Mini-DST Applications for Shell Deepwater Malaysia
Authors: Daungkaew S. , Harfoushian J. H. , Cheong B. , Akinsanmi O. , Yeo J. , Toulekima S. 
Published: December 2007

AbstractExploration and appraisal campaigns for deepwater environments are a continuous challenge in today's operations. Data acquisition in such environments requires reservoir information of the highest quality before expensive development plans can be put in place. New technology, real time monitoring and integrated reservoir data are essential to understand such reservoirs. Another challenge presented by thinly bedded reservoirs is the presence of vertical heterogeneity and varying layer flow properties.Wireline formation testers have been commonly used to acquire formation pressures pressure and reservoir fluid samples for a number of decades. Many hardware technologies and interpretation methods have been developed to acquire better quality reservoir information. Dual packer wireline formation testers offer an alternative an additional way to selectively straddle a section of a reservoir and provide the capability to conduct controlled local production and interference as well as to enable the capture of reservoir fluids. Formation permeability, anisotropy, skin factor, vertical connectivity and zonal productivity index are additional reservoir information that can be obtained from a mini-Drill Stem Test (mini-DST) and a Vertical Interference Test (VIT).Pressure transient analysis of a mini-DST data however in such reservoirs is challenging due to the associated uncertainties such as layer flow compartments and flowing fluid viscosity. This paper discusses the use of integrated reservoir information obtained from Downhole Fluid Analyzers (DFA), borehole images, and numerical simulation models to minimize these uncertainties. A systematic pressure transient analysis method for mini-DSTs is also introduced.Reservoir parameters obtained from mini-DSTs in thinly laminated deepwater reservoirs are then compared with other available static and dynamic reservoir information such as petrophysical data, core analysis, well tests, production logs, and single probe wireline formation tests in order to obtain accurate interpretation results of highest consistency.Field examples will be discussed which show that smaller scale pressure transient tests often have an advantage over full scale well tests testing in terms of providing detailed layer flow behavior, vertical connectivity and flow potential in thinly bedded environments. It will also be noted that the radius of investigation of a mini-DST is limited, typically within tens of feet. This paper demonstrates using field examples that reservoir boundaries can be detected when sufficient radius of investigation is achieved. In addition, the understanding of limitations and advantages will allow the proper selection of test types in order to meet specific objectives and maximize the full potential use of acquired data for field development plans in thinly laminated deepwater environments.
Light Well Intervention in the Asgard Field (Norway) as a Tool for Improved Reservoir Management
Authors: Viken V. , Hovde E. , Sletfjerding E. , Storoe P. A. , Mjaaland S. , Sand G. A. , Vassenden F. , Lerdahl T. R. 
Published: December 2007

Abstract
The Asgard licence, operated by Statoil, has been a major user of light well intervention (LWI) services since 2003. Based on the value of the results, this subsea field will continue using LWI as a reservoir management tool in the future. The main field, Smorbukk, is a high temperature gas condensate discovery that is developed with 20 commingled producers and 12 gas injectors. The reservoir complexity, commingled production and injection strategy for the wells has necessitated regular data acquisition. The data has been implemented in the reservoir models, resulting in improved reservoir management.
During the 4 years of LWI operations on Asgard, the scope of work has increased. The operational experience gained has developed a potential for further development of LWI. Integrated operations (IO) have increasingly been applied throughout the LWI campaigns during witnessing and quality control of well operations (e.g. production logging). Offshore to onshore communication of real time data and video-conferencing have been made possible.
The development of light well intervention methods has made data acquisition in subsea wells more economically attractive.
The data acquired in the campaigns has lead to:
– Improved Recovery based on better zone control for injectors and producers. – Identification of candidate intervals for closing off high GOR zones and directing injection gas into optimal zones. – Increased confidence in reservoir model as basis for infill wells.
Improvements through use of IO:
– It became possible for an onshore production engineer to perform an offshore day shift without travelling offshore. – IO has improved the speed and quality of decisions made through more effective involvement of onshore specialists. – IO has reduced the cost of the overall programme.
Non-Darcy Flow Effects in Dual-Porosity, Dual-Permeability, Naturally Fractured Gas Condensate Reservoirs
Authors: Ramirez B. , Kazemi H. , Ozkan E. , Al-Matrook M. 
Published: December 2007

Abstract
This paper addresses the retrograde condensation behavior in natural fractures and in the near wellbore region of a naturally fractured reservoir (NFR). The study includes the combined effect of non-Darcy flow in presence of retrograde condensation and wellbore damage on pressure transient analysis of naturally fractured reservoirs. A single well compositional model was constructed and used to evaluate both the early-time and late-time characteristics of the pressure transient data.
In naturally fractured reservoirs the high velocity region could be substantially beyond the near wellbore region because of the narrowness of the fractures. To assess this situation, draw-down, build-up and multi-rate tests were simulated in rich gas and lean gas condensate reservoirs. It was concluded that the gas condensation in the near wellbore region significantly increases the calculated skin factor beyond the physical damage.
Offshore Natural Gas Liquefaction Process Selection and Development Issues
Authors: Wood David , Mokhatab Saeid , Economides Michael J. 
Published: December 2007

Abstract
Liquefying natural gas on an offshore facility servicing an underlying gas field has yet to be sanctioned anywhere in the world, in spite of several feasibility studies demonstrating its potential viability. The perceived risks associated with deploying unproven technology in a high construction cost and volatrile gas price environment have so far inhibited offshore liquefaction projects. Such technology however has the potential to unlock substantial volumes of remote and otherwise stranded natural gas for commercial exploitation.
With strict no flaring aspirations in many countries discovering associated gas can pose obstacles to developing an oil field if no gas utilization strategy is commercially viable. Key issues for offshore gass liquefaction processes are: compactness (low weight–small footprint), ease of operation, process safety, and efficiency.
Particular attention is paid to the lower-efficiency turboexpander processes for plant capacities up to 3 million tons per annum (MTPA, about 0.43 Bcf/d). These cycles offer several advantages over the alternative optimized cascade and mixed refrigerant (MR) liquefiers..
Experimental Validation of Pore-Level Calculations of Static and Dynamic Petrophysical Properties of Clastic Rocks
Authors: Jin G. , Torres-Verdín C. , Radaelli F. , Rossi E. 
Published: December 2007

Abstract
We present an integrated approach to calculate fundamental macroscopic static and dynamic properties of porous media, including absolute permeability, formation factor, relative permeability, capillary pressure, and resistivity index. The calculations are based on high-resolution three-dimensional (3D) digital images of actual clastic rocks acquired with X-ray computed tomography (CT). Pore-level simulations of single-phase fluid flow and electrical conduction are performed using the lattice-Boltzmann method and diffusion random walks, respectively. Two-phase immiscible fluids are geometrically distributed into the pore space of the synthetic rock using a simple percolation algorithm while enforcing capillary equilibrium. These simulations serve to calculate effective medium properties of macroscopic rock behavior that can be used to improve both the interpretation of well-log measurements and the prediction of multiphase flow properties.
To test and validate our pore-scale model, we consider three micro-CT images of quartzose sandstones with different petrophysical properties to perform both laboratory measurements and pore-level calculations. The calculated permeability is in good agreement with the corresponding laboratory measurements for clean sands, while it differs for the shaly-sand sample. For both cases, the computed formation factor is consistent with laboratory measurements. For the case of two-phase simulations of water-wet conditions, the derived capillary pressure, relative permeability and resistivity index closely agree with experimental measurements when immovable fluid saturations of oil and water are taken into account. Our simulations show that calculations performed on a small rock sample may not always be representative of heterogeneous rock formations. We also find that the amount of clay-bound water should be accounted for in pore-level petrophysical studies, especially for rocks containing a significant amount of clay minerals. Higher image resolution than available is needed to accurately quantify macroscopic petrophysical properties of such complex rock samples.
Multiphase Non-Darcy Flow in Proppant Packs
Authors: Barree R. D. , Conway M. W. 
Published: December 2007

Abstract
This paper builds on a model for single-phase non-Darcy flow in porous media presented in SPE 89325.1 In this work the generalized equation for single-phase non-Darcy flow is extended to multiphase flow conditions. Laboratory measurements of gas-water flow were conducted in several flow cells to determine relative permeability curves and the non-linear relationship between individual phase flow-rate and induced potential gradient over a wide range of input fractional flow conditions and over a range of Reynolds Numbers (Re). A model is presented to predict multiphase non-Darcy flow in porous media that is applicable to high-deliverability reservoirs and hydraulically fractured wells.
Fluid Movement Measurements Through Eccentric Annuli: Unique Results Uncovered
Authors: Moran Larry , Savery Mark 
Published: December 2007

Abstract
Historically, a cement job was considered successful if the casing could be centralized and if high flow rates could be maintained. Today, however, there are more situations where one or both of these criteria are difficult to satisfy. Centralization in highly deviated wells is often challenging, and wells with low fracture gradients place a ceiling on pump rate. Better understanding of fluid movement through eccentric annuli over a wide range of casing standoffs and flow rates is essential for proper cement placement. In addition, being able to predict where cement slurry is located around the casing is very important. For instance, with an eccentric annulus there is no guarantee that cement returns at surface/mud line means complete cement coverage around the casing. Annular fluid velocities can be quite different between the wide and narrow portions of an eccentric annulus. There currently exists limited measured data on flow through annular sizes common to primary cementing operations.
Therefore, a full suite of physical testing was performed to find differences in velocities and flow rates on the wide side vs. the narrow side of a true annulus. Nine models were built, each taller than two meters and each with unique annular geometries. The annular sizes chosen are common to primary cementing operations. The flow area was divided at the top of each model to capture wide and narrow side flow variations. The weight of recovered fluid vs. time was recorded and used to determine flow rates and velocities on both sides. In total, over 250 runs were performed in typical annular geometries with pump rates from 1 bbl/min to 7 bbl/min, fluid rheologies from water-thin to highly viscous, and standoffs from 50% to 85%. While most results verified current industry best practices, other results were quite unexpected, for instance, higher annular velocities on the narrow side under certain conditions. A comprehensive analysis of these results and an appraisal of their potential benefits are presented.
New Constant-Rheology Synthetic-Based Fluid Reduces Downhole Losses in Deepwater Environments
Authors: Rojas Juan Carlos , Bern Peter , Plutt Louise Jacobson , Romo Louis , Greene Bob , Irby Roger , Trotter Neil , Dye Billy , Sharma Nitin 
Published: December 2007

Abstract
Drilling in deep water environments, such as the Gulf of Mexico (GoM), presents the potential for a variety of wellbore and operational problems. Wellbore stability, rates-of-penetration (ROP), hole cleaning, and pressure management are but a few of the key operational parameters affected by the choice of drilling fluid for a given well. Synthetic-base muds (SBM) provide excellent wellbore stability and maximum ROP, particularly in combination with PDC bits. Conversely, management of equivalent circulating density (ECD), pump initiation and surge pressures are more difficult to control with SBM due to the effects of temperature and pressure on rheological properties. The inability to effectively control these drilling parameters can result in catastrophic lost circulation events, which negatively impact operating costs arising from non-productive time (NPT), as well as the high unit cost of the SBM.
This paper highlights the development and application of a new constant-rheology synthetic-based mud (CR-SBM), designed to overcome the problems associated with pressure management when using SBM in deepwater operations. Unlike conventional SBM, this new fluid exhibits a "constant rheology" profile under the conditions encountered in deepwater operations. With the fluid's constant rheology profile, downhole surge pressures and ECD are minimized, thus reducing the frequency and severity of lost circulation events. In addition, the CR-SBM has consistently facilitated delivery of hole cleaning and barite suspension objectives in directional wells.
The CR-SBM presented in this paper is unique in the sense that the near constant profile of key rheological properties was achieved using organophilic clay and without the use of special emulsifiers. In general, the components of the CR-SBM are the same as conventional SBM. Case histories are presented that demonstrate the degree to which the new CR-SBM increases deepwater operational efficiency by reducing downhole mud losses and non-productive time.
The Use of a Fully Coupled Geomechanics-Reservoir Simulator to Evaluate the Feasibility of a Cavity Completion
Authors: Zuluaga E. , Schmidt J. H. , Dean R. H. 
Published: December 2007

Abstract
Cavity completions have been widely used to increase productivity from non-conventional sources such as coalbed methane reservoirs and "heavy" oil from weakly consolidated formations. In the 1990s, the technique was applied to conventional wells where massive sand production was allowed with the objective of creating a cavity. The benefits expected from a cavity completion are four-fold: 1) increase in PI by reducing skin, 2) increase in effective wellbore radius 3) creation of an enhanced permeability (dilatant) zone near the wellbore, and 4) decrease in pressure drop near the wellbore to values below the critical threshold for sanding.
Even though there are analytical tools available for predicting the initiation of sanding for simple well configurations, there are very few models that are capable of predicting cavity stability or cavity growth for general field applications. This paper introduces results from a fully-coupled geomechanical/reservoir simulator, GMRS®, which predicts cavity geometry evolution, sanding rates, cavity stability/instability, and production enhancement because of the creation of a cavity.
In this study, GMRS® is used to investigate the feasibility of a cavity completion in a well located offshore West Africa. This well started producing moderate amounts of sand in 1993. GMRS® is history matched with historical production data prior to sand predictions, and is used to investigate cavity initiation and growth for the well. An axisymmetric model is used with the reservoir treated as a poroelastic-poroplastic material with hardening. Porous flow is modeled as a black-oil two phase (oil and water) flow model. For the well investigated, sensitivity studies with varying formation properties predict that sand production and cavity generation will be unstable.