bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas Condensate Field Development Plan by Means of Numerical Compositional Simulation
Authors: Huerta V. A. , Lanchimba A. , Villagra L. , Chacon R. , Peru Repsol , Savoy E. , Colonomos P. 
Published: December 2010

Abstract
During the latest years, some gas condensate fields have been discovered in the Peruvian Amazonian rainforest. One of these fields is an anticline structure controlled by a reverse fault norwest – southeast; a wildcat well, drilled at the top, tested gas and condensate from NIA, NOI and ENE reservoirs; commercial decision on developing this gas condensate field will strongly depend on estimating its hydrocarbon potential.
Structural, rock-type, fluid-type and reservoir performance uncertainties are closely linked to 2D seismic grid and restricted information implicit to this exploratory well. A conceptual compositional simulation model was built for this gas-condensate field during its early stage to integrate seismic interpretation, petrophysical analysis, fluid behavior, and eventually, to come up with a reasonable estimation of resources, predict production performance and visualize development options.
Structural uncertainties were addressed by testing some geology maps, which were prepared with different velocity models for time to depth conversion. In addition, rock properties were sensitized with multiple deterministic and probabilistic executions taking into account ranges and cut offs of analogous fields. The fluid was characterized by means of two equations of state Peng-Robinson of three parameters and clustered into 13 pseudocomponents (for NIA and ENE-NOI reservoirs); despite sampling was not strictly representative, a calibration process was successfully done with experimental observations of PVT tests to account for gas, condensate, as well as, condensable gases production. And, DST results were matched to a VLP wellmodel.
A holistic analysis was carried out by integrating compositional simulation to sensitize production performance, and montecarlo simulation to evaluate for field size uncertainty when estimating gas and liquid resources. As a result, a matrix was designed to visualize and evaluate the most feasible development alternatives: depletion, depletion supported by a medium-size aquifer, partial and full cycling. 3D-Seismic and further appraisal wells will be useful towards reducing uncertainty of simulation model output and improving development decision-making process.
Innovative Methodology to Revitalize a Heavy-Oil Mature Field by Identifying Opportunities to Apply New Cycles of Steam Injection
Authors: Uribe J. P. , Pinilla J. F. , Cabrera D. 
Published: December 2010

Abstract
Tia Juana is a giant heavy oil field located along the Eastern shore of the Maracaibo Basin in Venezuela. This mature field has been producing oil of 12.6 API° from eight unconsolidated reservoirs from Miocene sandstone formations at 1200ft depth since 1928. The OOIP is 11.48MMMBBls with 3.18MMBBls of official recoverable reserves and cumulative production of 1.93MMBBls. This mature field has a long and rich history on which different recovery technologies have been proved such as: Cycle Steam Injection, Steam Drive, In Situ Combustion and SAGD: However, Cycle Steam Injection is by far, the most cost- efficient method to produce such heavy oil reservoirs.
High operating expenses affected by relative low production rates are usually exhibited by mature fields, heavy oil projects are additionally affected by the decreased price associated to oil quality. Under these conditions, an innovative methodology for economic value-adding opportunities to fields such as Tia Juana, is imperative in order to assure economic equilibrium for the project.
This paper presents an innovative methodology to boost the productivity scenario of mature heavy oil projects by the identification of opportunities to recover reserves, development of additional steam cycles in existing and new wells. The presented methodology is capable of quickly identifying wells with potential to be steam stimulated, quantity of possible cycles possible and predicted cumulative oil per cycle. This analysis was performed based on 2700 wells on which more than 9000 cycles and 43MM Tons of steam were injected.
The methodology includes six basics steps: production history review, conventional decline analysis, volumetric reserves estimation, determination of the well drainage radius and wells interference analysis, EUR calculations and the establishment of a correlation to predict the well behavior related to the Cycle Steam Injection. All these steps were integrated by an automated tool designed to manage the huge quantity of information in short time, honoring the cost and the efficiency issues. The application of this methodology allowed identifying the recovery of 108MMBBls by performing 2409 Steam Cycles in 563 existing wells (Fig. 7), and 113MMBBls by executing 3116 cycles on 576 new wells and finally allowed to adequately rank the opportunities based on the potential of reserves identified.
A New Approach to Hydraulic Fracturing With Relative Permeability Modifiers
Authors: Armirola F. , Machacon M. , Romero R. , Perez G. , Lastre M. , Ortega A. , Milne A. 
Published: December 2010

Abstract
In Colombia, relative permeability modifiers (RPMs) are often included in fracturing fluids to limit water production in wet producers. However, the results of their application are mixed. Since many reservoirs have an oil/water contact, or are close to an oil/water contact with poorly defined barriers, the fracture propagates into the water with minimal leakoff of the RPM into the fracture faces. In theory, the RPM polymer present in the interstitial water of the fracturing fluid leaks off into the fracture faces, as the hydraulic fracture propagates. For this to occur requires an inefficient fluid with high fluid loss. However, the properties of RPM fracturing fluids are similar to those of conventional fracturing fluids, highly viscous with leakoff control to ensure adequate fracture geometry and proppant placement. These properties favour vertical height growth of the hydraulic fracture and limit RPM leakoff into the fracture faces.
These limitations led to the development of a new fluid and placement techniques, with the objective of increasing the success rate of hydraulic fracturing in wet producers. A linear fluid comprised of polyacrylamide and polysaccharide polymers with a viscosity enhancer. The viscosity of which can be adjusted between 100 and 200 cp at 100 sec-1 over a wide range of temperatures. The relatively low viscosity of the fluid aids in limiting the net pressure and the risk of fracture height growth, in formations with low stress profiles. The addition of fibers provides a mechanical means to suspend and transport proppant, when deemed necessary. Hence, high fluid viscosity is no longer required for efficient proppant transport. By adjusting the ratio and concentration of the polymers, it is possible to independently adjust the viscosity and leakoff control of the fluid as a function of the formation permeability and stress profile. Doing so ensures that the desired fracture geometry is achieved while ensuring adequate leakoff to treat the fracture faces.
A fracturing campaign using this newly developed fluid in a mature field in Colombia resulted in an incremental oil production of 12%, while decreasing the water cut by 13%. This demonstrated that reservoirs that were not previously considered candidates for hydraulic fracturing can now be treated without increasing the water/oil ratio (WOR).
The use of this fluid, along with a new treatment design methodology, makes it possible to hydraulically fracture reservoirs with, or close to, an oil/water contact. This effectively extends the life of mature fields that are approaching their economic limits.
Surge and Swab Pressure Predictions for Yield-Power-Law Drilling Fluids
Authors: Crespo Freddy , Ahmed Ramadan , Saasen Arild 
Published: December 2010

Abstract
Surge and swab pressures have been known to cause formation fracture, lost circulation and well control problems. Accurate prediction of these pressures is of crucial importance in terms of estimating the maximum tripping speeds to keep the wellbore pressure within specified limits of the pore and fracture pressures. It also plays a major role in running casings, particularly with narrow annular clearances. Existing surge/swab models are based on Bingham Plastic (BP) and Power law (PL) fluid rheology models. However, in most cases, these models cannot adequately describe the flow behavior of drilling fluids.
This paper presents a new analytical solution, which is casted into a simplified model (dimensionless correlation) to predict pressure surge in a more convenient way. The steady state laminar flow equation is solved for narrow slot geometry to approximate the flow in concentric annulus with inner pipe axial movement considering yield-power-law (YPL) fluid. The YPL rheology model is usually preferred because it provides a better description of the flow behavior of most of drilling fluids. The analytical solution yields accurate predictions, though not in convenient forms. Thus, a numerical scheme has been developed to obtain the solutions. After conducting an extensive parametric study, dimensional analysis techniques were applied primarily to develop a simplified model that does not require a cumbersome numerical procedure. The new model is expressed in terms of dimensionless parameters.
The performance of the new model has been rigorously tested. Comparisons of the model predictions with previously published results have shown a satisfactory agreement. In most cases, the model makes better predictions in terms of closeness to relevant field measurements. That is due to the application of a more realistic rheology model. The presented model is very useful for slim hole, deepwater and extended reach drilling applications.
Drilling Process Creates Data Issues Requiring Innovative Data-Gathering and Interpretation Techniques
Authors: Pope Robert W. , Smith Charles H. , Mirzadeh Tahereh , Ramakrishna Sandeep 
Published: December 2010

Abstract
Directional-drilling processes that involve downhole motors, diamond bits, and bent subs have substantially changed the dynamics and economics of drilling to smaller, and more specific, geologic targets. This process produces some drilling-induced artifacts that include grooves and bit chatter in the wellbore wall. These created environments radically affect the measurements of density/neutron logs. In some cases, the alteration is so great that it affects resistivity logs, which makes the needed log properties impossible to determine with any accuracy.
The porosity measured by the density log appears to cycle high and low as the density pad loses and regains contact with the formation. The neutron porosity is also affected in many cases, exhibiting an identical cyclical character. The porosity measured by either traditional log cannot deliver a correct porosity, which leads to a cross-plot porosity estimate that is not accurate or useful. Another method must be used that does not depend on a smooth wellbore wall.
Dipmeter analysis is also affected because drilling-induced artifacts can be misinterpreted as geologic events. In many cases, the drilling process creates grooves that spiral down the wellbore. These grooves provide very distinct electrical contrasts, and the analyst may interpret them as actual geologic features. The use of an oil-based mud system provides an additional complicating factor that contributes to challenging dipmeter interpretations. Oil-based dipmeter interpretation was not consistent with expected results.
The solution to these difficult interpretation challenges requires the use of a different set of logs that provide answers independent of borehole quality. In this paper, we show how centralized, mandrel-deployed nuclear magnetic resonance (NMR) logs, unaffected by borehole irregularities, were used to define effective porosity. We also show how oil-based imagers were used to differentiate between drilling-induced grooves and beds or formation boundaries.
Gas Diffusivity Measurement in Reservoir Fluid at Elevated Pressures Systems for Transient Shut-in Modeling
Authors: Zainal Suzalina , Yee Hon Vai , Saaid Ismail M. 
Published: December 2010

Abstract
Gas-liquid diffusivity is investigated for many different oil recovery applications. Most interest is in the gas-oil diffusivity for enhanced oil recovery applications such as miscible gas flooding, immiscible carbon dioxide WAG (Water-Alternating-Gas) flooding and non-thermal heavy oil recovery by solvent injection. Other study includes the analysis of gas-water diffusivity to understand the methane hydrates formation. In designing an enhanced oil recovery process, for instance, further information on the rates and amount of mass transfer by diffusion is required. The focus is to have better insight of the mass transfer mechanisms, particularly at the reservoir level.
A more downstream application of gas-liquid diffusivity measurement is its application in transient modeling. The interest is at the production tubing, primarily in describing the phase redistribution process in a shut-in well. Gas-liquid diffusivity has been suggested to account for the molecular interactions and distribution between the gas and oil phase in a producing well during transient flow. Mass transfer being the transport phenomena, causes the molecules in the fluids to rearrange to attain an equilibrium system. This process of rearrangement is transient and driven primarily by the concentration gradient in the gas and oil system. The diffusion coefficient parameter which is a function of mass transfer introduces a time factor to the overall phase segregation process. Higher diffusion rate is anticipated to contribute to faster phase redistribution and contrary if vice versa. In transient modeling for shut-in condition, this information is useful to enable accurate simulation of fluid redistribution period prior reaching equilibrium.
This paper presents the gas-liquid diffusivity measurement and analysis involving Malay Basin's hydrocarbon fluid samples and its applications to the transient shut-in modeling. It also highlights on the reliability of a published method designed for a heavy oil system when applied to Malaysian light to medium crude oil systems.
Practical Modelling of Asphaltene Related Damage in Volatile Oil Reservoirs
Authors: Restrepo A. , Ruiz M. , Rendón N. , Lopera S. 
Published: December 2010

Abstract
Asphaltene deposition related damage is a well known phenomenon during production of highly under saturated volatile oil systems. It's modelling and control has been broadly documented although this last practice has been restricted to the near wellbore region where its impact seems to be maximum and where treatments can be effectively deployed.
The following paper presents a modelling approach for the estimation of the asphaltene deposition profile in highly under saturated volatile oil systems. This profile would allow predicting effective permeability loss as a function of pressure provided a set of asphaltene content measurements taken at wellhead through time. A simple asphaltene solubility model coupled with laboratory measurements are combined to propose a precipitation-deposition model that estimates expected k losses when thermo dynamical changes such as methane injection or pressure depletion are present. The output from the model which is a k function of pressure was incorporated into a single well model to match well's actual response after near wellbore dissolution treatments and after injection gas appearance in the drainage area. Laboratory tests consisted of core flooding experiments that allowed obtaining basic relationships between mass of asphaltene deposited and damaged Ko.
The present model was developed as a tool for benefit estimation if an asphaltene dissolution technique is applied at reservoir scale. The present approach is proposed as a simple and practical way of estimating asphaltene related damage in compositional volatile oil reservoirs.
Improvements in Routine Core Analysis on Whole Core
Authors: Perez C E. R. , Zapata A J. F. , Gonzalez M. , Herrera M. N. 
Published: December 2010

Abstract
A naturally fractured reservoir is composed by a system of fractures created by breakdown of the layers, caused by tectonic movements. Although all reservoirs have some fractured grade, only are considered naturally fractured, those where the system of fractures presents any effect upon flow of fluids.
Whole core analysis is critical for characterizing directional permeability in heterogeneous, fractured reservoirs. Whole core measurements are essential for heterogeneous reservoirs because small- scale heterogeneity may not be appropriately represented in plug measurements. For characterization of multiphase flow properties in heterogeneous rock, routine and special core analysis in whole core is also required.
In this paper, we provide an overview of routine and special core-analysis measurements on whole cores. Improved experimental equipments for measurement of routine core analysis on whole core (fluid saturation, clean, directional permeability, and porosity) under a maximum confining stress of 10,000 psi, were made in the ECOPETROL-ICP's routine and special core laboratories. The advantage of these equipments is that allows evaluating directional permeability (x, and, z) considering variations in permeability caused by fractures and other heterogeneities. Finally we discussed results from routine core analysis on whole cores for Colombian heterogeneous sandstone. Also in this paper the effect of scale (sample size) on the measured properties are also shown.
Planning and Interpretation of Offshore-Field Tracer Tests Using Accurate and Refined Tracer Simulations
Authors: Huseby Olaf , Sagen Jan , Wangen Magnus , Viig Sissel Opsahl 
Published: December 2010

Abstract
Tracers are chemical compounds or radioactive isotopes used to label injection water and gas in petroleum reservoirs. In inter-well tracer tests (IWTTs), well connections and fluid patterns can be established when the tracer appears in production wells. Tracer simulation is an invaluable tool to ease the planning or interpreting results of IWTT. In this paper we introduce a novel tracer simulation methodology which is based on a decoupling from the underlying reservoir simulation. The method- ology ensures accurate and very fast tracer simulation; with CPU times in the order of a few percent of ordinary reservoir simulation. The method is based on solving the tracer equations on a grid separated from the underlying reservoir simula- tion. The separate tracer grid can be refined, with significant improvements in the accuracy of the tracer solution, without affecting the speed of the reservoir simulation. Accurate refinement as well as localized tracer grid refinement is introduced and investigated. Local refinement is compared to global refinement, and we demonstrate that local refinement can be a valid strategy in many cases. We demonstrate the methodology on a real reservoir case, and show that predicted breakthrough times are significantly affected by the accuracy of the solution. The method improves accuracy by overcoming numerical diffusion through separate tracer-grid refinement. In our specific real case, the breakthrough time was underestimated by about one year in the solution obtained using standard methods. This was corrected using the new methodology. The large difference in simulated breakthrough time between the improved and corrected solution has important consequences for the planning and interpretation of IWTT.
Added Value by Resistivity Images for Wellbore-Strengthening Strategy Development in Cashiriari Field, Peru
Authors: Uribe R. , Carrillo R. , Cassanelli J. P. , Barret S. , Airoldi C. 
Published: December 2010

Abstract
The Cashiriari field is located in the tectonically stressed Ucayali basin, on the eastern flank of the Andes Mountains in Peru. The difficult and complex structure of the field shows naturally fractured formations, especially in the sandstone reservoirs. There are highly unstable shales which also have a narrow stability mud window in the same section of the wellbore. The wells in these formations suffer events such as mud losses, cavings, poor hole cleaning, tight holes, differential sticking, and poor hole quality.
Two factors cause severe mud losses in the Cashiriari field: natural fractures and mud equivalent circulating density greater than minimum horizontal stress. In addition, the shale lithologies require high mud weight to control instability. To cope with these events, the operator and the service Company developed a "wellbore-strengthening" strategy that used calcium carbonate and lost circulation material to cure mud losses and to increase fracture resistance over minimum horizontal stress. Mud losses were controlled or eliminated. The geomechanical model limits were increased—up to 0.8 ppg over the minimum horizontal stress for drilling and up to 1.6 ppg for cementing jobs.
A logging-while-drilling (LWD) resistivity tool was introduced in this project in 2009 to acquire additional logging data. This solution provided excellent LWD image quality that allowed the identification of the natural fractures as drilling progressed. With data from a spectroscopic tool, the understanding of the fluid loss intervals improved significantly. The understanding of the lost circulation regime increased significantly as natural (both open and closed) and induced fractures were recognized, along with extremely high matrix permeabilities. These analyses were quantified, and improved drilling practices were applied. Most significantly, these data permitted the design of cementing operations within extremely limited operating windows.
Advanced logging, wireline information-gathering technologies, and certain drilling practices led to solutions in the difficult drilling conditions. The data helped the team to plan a mud window which minimized wellbore stability issues and provided the control needed of the drilling fluid losses. We also gathered data for a complete formation evaluation as drilling progressed. The real-time data allowed us to make informed decisions to justify changes or to make adjustments while drilling.
Deepwater Equipment for Flooding, Cleaning, Gauging, and Strength Tests
Authors: Guimarães C. , Machado F. , Gasparini L. 
Published: December 2010

Abstract
This paper describes a subsea pigging and hydrotesting unit (SPHU) that provides technology for remote flooding and testing of pipelines in water depths up to 2000 m (6,562 ft). The benefits of having a submerged pump that uses seawater for tests are related not only to safety, but also to schedule and deck-space optimization.
The SPHU has the capability to filter and chemically treat flooding water while continuously regulating and monitoring the flooding and pigging operations. The system includes a subsea data logger that allows remote monitoring and logging of pressure, temperature, flow rates, and volumes. Once in place, the SPHU uses power available from a remotely operated vehicle (ROV). The ROV is used to control the rate of pressure increase in the pipeline by varying the flow rate provided by the ROV-driven pressurizing pump.
One of the most significant advantages provided by this equipment is that strength-test operations can be completed entirely on the seabed, moving the risks posed by high-pressure fluids to a location far from personnel. Various versions of the SPHU have been successfully deployed on over 90 pipeline operations to date, adding significant value to offshore projects by allowing more flexible and efficient usage of vessels. To better illustrate the use and benefits provided by this unit, case studies will be presented based on operations performed in Brazil in the last two years.