bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Rational Approach to Multilateral Project Planning
Authors: DeMong Karl , Mason Stan , Al-Yami Hussein 
Published: December 2007

Abstract
In the past, junction construction technology has driven the design of multilateral wells. This practice has led to technical successes that may or may not have met all of the operator's desired well objectives. These projects have often been regarded as less than successful from an economic point of view. This regard is partly due to the way that junction construction has been viewed. Junctions are presently classified by looking at the technical differences in how they are constructed, such as TAML levels (Technology Advancement – Multi Laterals)1. Although this method is suitable for looking at junction construction complexity, it does not address directly what the junction does in service. Another approach would be to drive the design using information about reservoir/production requirements. Looking at functional groups of junction features will allow the drilling or completions engineer to make sense of the myriad of available junction systems. This technique can help optimize the multilateral junction type selection for a given project.
The process of planning multilateral projects from conception through well design will be discussed with a focus on using a functional classification map to clarify the junction requirements. The Functional Classification Method will assist engineers in comparing equipment options. This comparison is accomplished by, first, defining the reservoir and economic drivers, and, then, by selecting the appropriate junction attributes. Furthermore, the method will provide a process for assembling the data required to prepare the final well design and to prepare precise tender documents. To illustrate this method, recent examples from the Middle East will be presented.
Application of Water Injection/Falloff Tests for Reservoir Appraisal: New Analytical Solution Method for Two-Phase Variable Rate Problems
Authors: Levitan Michael M. 
Published: December 2007

Abstract
The challenges of reducing or eliminating emissions associated with well testing operations during reservoir appraisal have revived interest in water injection/falloff tests. However, the two-phase flow and injection induced temperature changes associated with injection/falloff tests complicate the problem of well test analysis. Strictly speaking, these effects make the pressure transient problem non-linear and preclude using conventional superposition technique to construct solutions for variable rate problems.
In this paper, we present a new analytical method for accurate solution of the pressure transient problem for two-phase flow associated with water injection/falloff tests. The solution algorithm allows one to compute the solution for any step-wise constant rate sequence that includes multiple injection and falloff periods. The method is general and can be used for water injection governed by any physically meaningful relative permeabilities as well as for pistonlike displacement.
Quantifying Production Impairment Due To Near-Wellbore Condensate Dropout and Non-Darcy Flow Effects in Carbonate and Sandstone Reservoirs With and Without Hydraulic Fractures in the Ghawar Field, Saudi Arabia
Authors: Ahmed Mahbub , Al-Qahtani M. Y. , Zillur Rahim 
Published: December 2007

Abstract
Hydraulic fracturing in the sandstone and carbonate reservoirs has been adopted as the primary means to enhance production from the gas wells in the Ghawar field of Saudi Arabia. The initial incremental production from acid treatments is readily noticed from all stimulated wells in the Khuff carbonates. For the Pre-Khuff sandstones, because of the sanding tendency of the unconsolidated formation, selective perforations and indirect fracture treatments are performed to stimulate the wells. Thus the incremental production is not ascertained through actual production data, rather the post-fracture production is compared to the simulated pre-fracture potential. In either case, as the production continues and the reservoirs are depleted, production impairment occurs due to potential water encroachment, condensate build up around the wellbore, and changes in non-Darcy flow effects as gas enters production string.
This paper presents a comprehensive study of the impact of pressure depletion on production for Ghawar gas- condensate reservoirs. The paper quantifies the effect of condensate dropout on the well productivity with and without induced hydraulic fractures. The effects of non-Darcy flow have also been investigated and presented. A compositional model has been used to forecast and optimize long-term production under various reservoir conditions and operational scenarios.
A Fast and Direct Method of Permeability Measurements on Drill Cuttings
Authors: Egermann P. , Lenormand R. , Longeron D. , Zarcone C. 
Published: December 2007

Abstract
Permeability is one of the most important petrophysical parameter for reservoir characterization but the most difficult to obtain. Logs provide a good estimate of porosity and saturations, but the accuracy on permeability derived from NMR is rather poor. So far, reliable values of permeabilities are only obtained from laboratory measurements on core samples for local measurements and well testing for a larger scale averaged determination.
We present an original method for measuring the permeability of drill cuttings without any specific laboratory conditioning (cleaning, coating, etc.). A volume of about 100 cc of cuttings is placed in a pressure vessel. The cell is then filled with a viscous oil. The process of oil invasion into the cuttings always traps a certain amount of gas. When a pulse of pressure is applied on the cell, the oil enter into the cuttings thanks to the gas compressibility. The permeability is then derived from the dynamic of the oil invasion by using a simple model.
The method was tested by using various samples of crushed rock samples of known permeability. An excellent reproducibility and a good agreement between cores and cuttings permeabilities were found for many decades of permeabilities. This method presents many advantages. The measurements can be performed in a few minutes, leading to the possibility of operating on-site during drilling. The limitations of the method are mainly related to the size and the representativity of the drill cuttings.
In developing this method, our purpose is not to replace core analysis, but rather to provide an additional cheap and quick information on reservoir characterization.
Modeling of Wax Deposition in Pipelines from Irreversible Thermodynamics
Authors: Banki Reza , Firoozabadi Abbas 
Published: December 2007

Abstract
Wax deposition in flowline of some crude oils and gas condensates in offshore is a serious problem. Deposition often reduces flow capacity and may block the line and reduce flow rate and increase the production cost substantially. In the last ten years, there have been a number of studies in modeling the deposition processes. All these models assume that the Fick's law of diffusion adequately describes the mass diffusion flux of wax-forming species from the oil or gas phase towards the wall. Wax deposition in flowlines is the result of radial temperature gradient and subsequent diffusion mass flux of species in the radial direction. However, the diffusion mass flux of species in the radial direction cannot be described by the Fick's law of diffusion. In this work, we first write the expression for diffusion flux in terms of: 1) molecular diffusion, and 2) thermal diffusion. Thermodynamics of irreversible processes is used to model the diffusion flux at non-isothermal conditions. We avoid the use of chain rule to relate composition gradient to temperature gradient. We also include the radial convective velocity in problem formulation for the laminar flow for the first time. In our formulation, both the mass balance and energy balance are written for a multicomponent two-phase solid-liquid mixture. A control volume method is used to solve the coupled problem of mass, momentum, and energy balances. A numerical example for a binary mixture shows that at long times, of the order of several days and longer, both molecular and thermal diffusion affect the hardening of the layer in which the wax forms.
Subsea Heat Bank - An Alternative Thermal Insulation Method
Authors: Falk Kristin , Kaste Vegard , Håheim Svein , Damsleth Per 
Published: December 2007

Abstract
Subsea equipment for oil and gas production such as manifolds, X-mas trees and templates require thermal insulation in order to prevent too rapid cool-down during a production shutdown, potentially causing hydrate formation that can plug the piping. The insulation materials used today are expensive to produce and time consuming and costly to apply, yet may still leave hard-to-access areas with inadequate protection.
A Heat Bank where the subsea equipment is covered and the fluid trapped inside is heated during normal production is proposed as an alternative to conventional insulation. During shutdowns the heated fluid inside the insulated cover keeps the production equipment warm.
This article gives a detailed description of the Heat Bank and the analysis methods used for design. A thermal model based on empirical relations for natural convection and the Boussinesq approximation illustrates the functionality of a Heat Bank. This analytical model is also compared to CFD (Computational Fluid Dynamics) simulations.
The analysis reveals that the Heat Bank concept offers significant increase in cool-down time compared to traditional solutions. Other advantages include potential cost savings, reduced engineering and manufacturing times, and avoiding cold spot problems that are difficult to resolve with conventional methods. This opens for new possibilities for cost-effective field development in deep water where thermal insulation is critical to flow assurance and thereby field development economics.
Assessment and Modeling of High Permeability Areas in Carbonate Reservoirs
Authors: Massonnat G. , Pernarcic E. 
Published: December 2007

Abstract
In carbonate reservoirs, heterogeneity is usually driven both by the depositional and the diagenetic patterns. When original reservoir properties have been strongly modified by dissolution, the assessment and the modeling of karstic high permeability areas constitute key issues during reservoir appraisal.
In this paper, a very innovative methodology is proposed for the evaluation and modeling of reservoirs in which dissolution occurred at an early stage, and was controlled by sequence stratigraphy.
Using stochastic models of depositional facies built using Neptune (a modeling methodology/tool that uses cubes of facies proportions derived from paleobathymetry), the probability for facies to be affected by early karstification is evaluated. This can be possible thanks to the 3D grid of paleobathymetry previously computed with Neptune.
Then, the distinction is made between the regions potentially exposed to dissolution, and the regions with no chance to be exposed. The last stage consists in simulating petrophysics according to the depositional facies and its diagenetic behavior.
Such a methodology enables to take into account the 4D aspect of the reservoir construction. The prediction and the management of the areas of emersion are possible, and contribute to obtain significant advances in the realistic aspect of the 3D distribution of reservoir properties in stochastic models. Moreover, consistency between sedimentology, diagenesis, and petrophysics is input at a very high level in the model. This makes possible to preserve the key heterogeneity in reservoir models for fluids flow simulation.
Application to an oil field in Middle East illustrates the methodology.
3D Modeling of Stratigraphically Controlled Petrophysical Variability in the South Wasson Clear Fork Reservoir
Authors: Jennings James W. , Lucia F. Jerry , Ruppel Stephen C. 
Published: December 2007

Abstract
Petrophysical heterogeneity in the South Wasson Clear Fork (SWCF) reservoir and other shallow-water platform carbonates in the Permian Basin and elsewhere is composed of a large-scale stratigraphically controlled component and a small-scale poorly correlated component. The large-scale variability exists as a flow-unit-scale petrophysical layering that is laterally persistent at interwell scales and produces highly stratified reservoir behavior. Modeling these large-scale heterogeneities as trends using moving averages within a high-resolution sequence-stratigraphic framework reduced the requirement for arbitrary kv/kh adjustments to inhibit cross-flow in waterflood simulations. Carefully controlled power-averaging effectively captured the rate-enhancing effect of the small-scale variability.
Characterisation of Low Permeability Gas Condensate Behaviour by Intensive Reservoir Monitoring
Authors: Richardson G. J. , Roux J. F. , Quinn P. , Harker S. D. , Sides L. E. 
Published: December 2007

Abstract
The Alwyn North complex is located in Block 3/9a of the northern North Sea, UK sector. Production commenced in 1987 from the Brent and Statfjord reservoirs. In 1995, the presence of an economic hydrocarbon accumulation in the Triassic was proven by platform well 3/9a-N33.
The Triassic geological environment encountered is semi arid, with moderate to high sinuosity channels, lacustrine and floodplain deposits. The Triassic Upper Lunde reservoir section is thick (approximately 700m) but the net to gross and permeability are low. Individual sand body dimensions can vary from tens of metres up to the order of several kilometres. The fluid is a gas condensate in the upper 450m of the reservoir overlying a volatile oil.
Intensive reservoir monitoring has proved invaluable in improving the understanding of field performance. Downhole permanent pressure and temperature gauges have been installed in all wells since the second appraisal well. Sixteen PLTs had also been run in the accumulation by the end of 2001, which allied to MDT and downhole gauge data, allowed to calculate the connected volume to the first six wells by two different methods.
The downhole gauges have also been used to monitor the evolution of the productivity index of the wells. Moreover, time lapse Pressure Build Up analysis has been carried out to investigate the evolution of the effective permeability thickness and skin factor with time. A quantification of the impact of condensate drop out has been attained, and a first correlation against petrophysical properties developed.
Recipe for Success in Ultradeep Water
Authors: Ehlig-Economides C. A. , Economides M. J. 
Published: December 2007

Abstract
Generally, for sandstone reservoirs, shallow deposits tend to be unconsolidated containing heavy oil, and deep deposits tend to be hard rock of low permeability containing gas. The result is an overall leveling of mobility, which relates directly to well potential. Carbonate reservoirs offer significant departures from sandstone trends, and this explains why 8 of the 10 largest and most prolific reservoirs are carbonate formations.
Typical trends are altered when a significant portion of the depth to the formation is water depth. More or less, the formation age to depth correlation follows depth below mud line rather than below the water surface. However, the fluids may have experienced pressures and temperatures that would accelerate the maturation process from heavy oil to light oil and, even, gas. The result would be much lower than typical fluid viscosity in very large- permeability sediments, leading to high mobility and extraordinary well productivity.
The paper makes the case that under ultra deep waters, in sedimentary environments such as the Gulf of Mexico, offshore Brazil and West Africa, reservoir quality and productivity can be readily inferred and even more to the point, the depth at which specific grade of hydrocarbons can be found. In particular, very large natural gas reservoirs are likely to lie beneath oil reservoirs, the latter containing also large volumes of gas in solution.
Information from some of the largest ultra-deep-water accumulations of hydrocarbons shows correlation of depth versus mobility, which is contrasted with data from terrestrial reservoirs. This phenomenon is explained through basic principles.
Improved Quantification of Fit-for-Purpose Saturation Exponents with a Maturing Core Database
Authors: Worthington Paul F. 
Published: December 2007

Abstract
A fit-for-purpose saturation exponent is specific to a given rock type and to a particular interpretative algorithm for the evaluation of water saturation. This concept is expanded to include the degree of maturity of the core database. Four data scenarios are enacted to derive data-specific values of fit-for-purpose saturation exponent using two type-algorithms. The first scenario assumes no core data beyond measurements of water saturation and resistivity index using simulated formation water. The second draws additionally on a measurement of porosity for each desaturated core plug. The third scenario further requires a dual-salinity determination of intrinsic formation resistivity factor. The fourth and most comprehensive scenario calls for a more complete electrical characterization of a core plug through multiple-salinity conductivity measurements. The value of these scenarios is examined by comparing the resulting predictions of water saturation with those obtained through the reference Scenario 4 and by cross-comparing the predictive performance of the type-algorithms.
The outcome is practically the same for the two type-algorithms. The first data scenario is erratic. The results of the type-methods converge through Scenario 2, for which similar water saturations are predicted by the two algorithms. Scenarios 2 and 3 furnish predicted values of water saturation that agree well with those resulting from Scenario 4. Because Scenario 2 has the smallest data requirement of these three approaches, it is proposed as the most effective way of deriving a fit-for-purpose saturation exponent and thence obtaining a meaningful evaluation of water saturation. This scenario therefore allows data needs to be optimized with the further containment of uncertainty in integrated reservoir description. Thus, both costs and risks can be reduced simultaneously.
Multiphase Flow: Can we take advantage of hydrodynamic conditions to avoid hydrate plugging during deepwater restart operations?
Authors: Leporcher Emile , Kinnari Keijo , Labes-Carrier Catherine , Maurel Philippe , Vandersippe Wilfried 
Published: December 2007

Abstract
High water flowrates envisaged in deepwater oil production systems create severe technical hurdles. In steady-state flow design conditions, adequate insulation of moderate length subsea flowlines and risers is expected to maintain the fluids out of the hydrate domain. The restart operation after shutdown will on the other hand need specific operational guidelines and design solutions to avoid hydrate plugging. Operational procedures may involve hot crude displacement or injection of thermodynamical inhibitors. Plug formation has by far a more serious consequence on the production regularity at the deepwater environment than at shallow water. A new R&D project was launched to identify cost effective and easily implementable procedures and build more confidence on transient operations with particular focus on start-up. Restart operations were experimentally simulated on a properly instrumented multiphase pilot loop in order to observe and analyse the flow conditions within and outside the thermodynamic hydrate domain. Different fluid systems were tested at different hydrodynamic conditions. The results suggest that a high energy hydrodynamic start-up procedure would allow to restart the production within the hydrate domain while low energy start-up would promote formation of hydrate plugs. In the low energy start-up the presence of the oil phase was observed to reduce the risk for hydrate plug formation.
ESPs and Intelligent Completions
Authors: Konopczynski M. R. , Moore W. R. , Hailstone J. J. 
Published: December 2007

Abstract
The value of intelligent well completions combined with ESPs comes from the capability to restrict or exclude production from specific zones experiencing water or gas breakthrough. This technology may be applied to horizontal wells, multilateral wells, wells that produce from commingled reservoirs, or wells that exploit layered, compartmentalized, or heterogeneous reservoirs. The control of production and water and/or gas breakthrough permits more efficient operation of the downhole pump, and improves ultimate hydrocarbon recovery. This paper presents the benefits of synergy, technologies available, and the issues that must be considered when combining intelligent wells with ESPs. A theoretical example is presented that illustrates the economic benefits of combining the two technologies, and it is followed by an offshore case history that puts theory to practice.
What is the Magic of Water in Producing Sand?
Authors: Vaziri Hans , Barree Bob , Xiao Yuxing , Palmer Ian , Kutas Mike 
Published: December 2007

Abstract
We performed a comprehensive sand prediction study of several deep, HPHT wells within a large reservoir and the findings revealed that, for these wells, common criteria based on critical drawdown, minimum bottomhole pressure, depletion or fluid velocity failed to predict the outcome by a relatively large margin. All these wells were subjected to relatively high levels of drawdown and also very high fluid velocities and, with the exception of one well, none showed any sanding until water production was encountered.
In this paper, we provide a rationale for why water can be highly effective in inducing sand production and we support our argument using advanced numerical modeling. This exercise also ranks the performance of some of the common tools and theories that are conventionally used for sand prediction. We also provide reasons why some of these models do not perform satisfactorily for the cases studied.
The originality of the work is in demonstrating that prior to sand production, the dis-aggregated rock (i.e., individual sand particles) around the wellbore is basically held together by the capillary tension which is destroyed by water flow. While the capillary tension appears to be insignificant (as it is in the order of 1 psi or so), it provides a significant resistance against sand mobilization. The importance of this issue has been quantified using advanced numerical modeling. This concept is vastly different from the previous theories that propose water weakens the rock through chemical interaction or changing the relative permeability.
Pressure Transient and Decline Curve Behaviors in Naturally Fractured Vuggy Carbonate Reservoirs
Authors: Camacho-Velázquez R. , Vásquez-Cruz M. , Castrejón-Aivar R. , Arana-Ortiz V. 
Published: December 2007

Abstract
This study presents a new way to model high secondary porosity, mainly vuggy porosity, in naturally fractured reservoirs.
New solutions are presented for two cases, where there is no primary flow through the vugs, which is an extension of the Warren and Root model, and where dissolution process of pore throats has created an interconnected system of vugs and caves. In both cases there is an interaction between matrix, vugs, and fracture systems. New insights are provided.
Both pressure and production responses during transient and boundary dominated flow periods are explored. In transient well tests, for the case where there is no primary flow through the vugs, a change of slope could be present during the transition period. Thus, this study shows that slope ratios of 2:1 of early or late-time segment versus transition segment do not necessarily imply transient interaction between matrix and fractures. It is also shown that the presence of vugs and caves may have a definitive influence on decline curve and cumulative production behaviors; therefore it is necessary to incorporate vuggy porosity in the process of type curve match.
Finally, the use of the methodology obtained in this work is illustrated with synthetic and field examples.