bluuebunny/crossref_metadata_2025_split huggingface dataset:
Practical and Successful Prevention of Annular Pressure Buildup on the Marlin Project
Authors: Vargo Richard F. , Payne Mike , Faul Ronnie , LeBlanc John , Griffith James E. 
Published: December 2007

Abstract
In late 1999, British Petroleum (BP) experienced a well failure in the Marlin development in deepwater Gulf of Mexico (GOM). Within hours of starting production, the production tieback casing collapsed, causing failure of the production tubing. Pressurization of outer annuli due to production thermal effects was identified as one of two possible root causes of the failure.
The oil and gas industry has been observing, documenting, and reporting cases of annular pressure buildup (APB) in annuli for several years.1 On land, platform, and spar-type wells having access to annuli, the problem can usually be dealt with by bleeding off the annular pressure as needed. Subsea completions, however, do not allow this capability, and the technology to provide access is still being studied. Especially susceptible to APB are deepwater developments in which the differential between mudline temperatures and flowing-production temperatures can exceed 125° to 200°F.
A key technique developed during the Marlin project to help prevent APB was the use of nitrified cementing spacers. These spacers provide a compressible cushion that can absorb the pressurization effects caused by thermal heating in the annulus. In addition to carrying nitrogen, the spacers can also provide adequate mud removal and remain stable for at least 72 hr. These features help prevent the migration of nitrogen into the riser prior to setting the wellhead seals. Based on a series of pressure/volume/temperature (PVT) tests and well design simulations, the minimum foam quality of nitrogen was determined.
Service company and operator engineering staffs worked proactively and integrated their efforts to identify, evaluate, plan, and implement multiple options for resolving this substantial well-integrity issue. This paper reviews the problems associated with APB, details the large-scale testing that was conducted, and the resulting best practices that help prevent APB from affecting the casing design. These best practices were successfully implemented on the Marlin subsea development, and other projects are also using these techniques.
Application of Transient Multiphase Compositional Tracking for Pipeline Flow Analysis
Authors: Rydahl Allan 
Published: December 2007

Abstract
This paper details the application of transient multiphase compositional tracking in a pipeline flow simulation study. Comparisons of results between the compositional modeling approach and results obtained using a precalculated table-based fluid property approach is presented. Both simulation models are based on the dynamic two-fluid theory commonly used to simulate transient multiphase flow in wells and pipelines. When comparing the simulation results with pipeline depressurization field data for one field case, the gas outlet rate and pressure is simulated with greater accuracy using the compositional tracking approach. For a second field case the simulation results are comparable for gas outlet rates and pressures although the compositional tracking overall is better. For liquid volumes the results are of comparable quality for both field cases.
Experimental Research on Downward Two-Phase Flow
Authors: Hernandez Ali , Gonzalez Leonor , Gonzalez Pedro 
Published: December 2007

Abstract
There are several applications in the Oil Industry where it is necessary to be able to predict the pressure drop in downward two-phase flow. One of these applications has to do with recent developments on simultaneous water and gas injection projects for reservoir pressure maintenance purposes. In order to be able to properly design surface facilities for the simultaneous injection of natural gas and water, a fairly good estimate must be made on the surface injection pressure required for a desired down-hole injection pressure. Unfortunately, there are very few correlations available in the literature that can be used for downward two-phase flow. Furthermore, field scale data that can be used to test these correlations is not available, so their predictive power is unknown.
In order to gain insight on pressure drop, flow patterns and liquid hold-up expected in downward two-phase flow, an experimental work was performed using 2 in I.D. pipes with water and air as process fluids. The experimental results are presented in this paper, together with a comparison of these results with the predictions of currently used correlations.
A General Scaling Method for Spontaneous Imbibition
Authors: Li Kewen , Horne Roland N. 
Published: December 2007

AbstractScaling the experimental data of spontaneous imbibition without serious limitations has been difficult. To this end, a general approach was developed to scale the experimental data of spontaneous imbibition for most systems (gas-liquid-rock and oil-water-rock systems) in both cocurrent and countercurrent cases. We defined a dimensionless time with almost all the parameters considered. These include porosity, permeability, size, shape, boundary conditions, wetting and nonwetting phase relative permeabilities, interfacial tension, wettability, and gravity. The definition of the dimensionless time was not empirical, instead, was based on theoretical analysis of the fluid flow mechanisms that govern spontaneous imbibition. The general scaling method was confirmed against the experimental data from spontaneous water imbibition conducted at different interfacial tensions in oil-saturated rocks with different sizes and permeabilities. A general analytical solution to the relationship between recovery and imbibition time for linear spontaneous imbibition was derived. The analytical solution predicts a linear correlation between the imbibition rate and the reciprocal of the recovery by spontaneous imbibition in most fluid-fluid-rock systems.
Forecasting Liquid Condensate and Water Production In Two-Phase And Three-Phase Gas Condensate Systems
Authors: Jokhio S. A. , Tiab D. , Escobar F. 
Published: December 2007

Abstract
This paper shows how to forecast liquid condensate and water production from gas and gas-condensate wells. The methodology is based on the Whitson and Fevang's5 method of handling fluid properties using two-phase pseudopressure function that not only takes into account the pressure dependence of the fluid properties but also retrograde behavior (phase change) of light hydrocarbons in the reservoir. Tedious mathematical treatment indicates that the oil phase production can also be predicted using the surface gas production in case of two-phase, and gas and water production data in case of three-phase producing wells.
To establish Inflow Performance, one needs relative permeability data along with PVT data. In this study, we have used pressure transient methods to obtain the effective permeability as a function of pressure. Once the correlation between the effective permeability and pressure is obtained, it is used in the pesudopressure integral. Sapphire well test simulator was used to simulate pressure test data and PVT data for condensate wells. The effective permeability correlation was developed from the well test analysis. This was done by simulating 2-phase and 3-phase gas-condensate reservoirs with reservoir pressure equal to P*.
The main source of the liquid condensate is considered the 1st region, closest to the wellbore, which is spread areally between the wellbore and the pressure P*, in the reservoir. Flow in this region is two phase in nature. Some of the liquid phase may go into the gas phase due to retrograde conditions if exist. Region-2 consists of liquid and the gas phase but it is assumed that the liquid condensate is immobile since the liquid saturation has not builtup enough to initiate flow. The pressure range in this region is from Pd to P*. The water production, however, is the contribution of the entire reservoir since no phase change is expected in the aqueous phase. More importantly, water phase is considered as the most reliable phase in gas condensate systems from engineering point of view, since water properties hardly change with pressure in the reservoir.
Two examples are solved with simulated data to show the use of the technique developed.
Real Options Applied to Selection of Technological Alternative for Offshore Oilfield Development
Authors: Dezen Francisco , Morooka Celso K. 
Published: December 2007

Abstract
The future outcome of a project is not usually predictable, and therefore uncertainty plays an important role into the process. Current economic models that support decision-making process are not always capable of indicating and accounting for the benefits of flexible field development plans.
One way to resolve this is to add real options valuation (ROV) into the economic model and to expand the decision-making process to accommodate this technique. The work presented on the paper describes a methodology that incorporates ROV into the analysis of different field development alternatives for deepwater.
Examples are presented in this paper to demonstrate that there is a difference in the total value of the projects when flexibility is accounted for. It is also highlighted the different manners that flexibility contributes to the project value and how to model a field development plan in order to analyse its flexibility.
New Approach for Interpreting Pressure Transient Test After Massive Acidizing Treatment
Authors: Valkó Peter P. , Mursal Fnu , Vance Harold 
Published: December 2007

Abstract
Interpreting a pressure transient test of an acidized well in the framework of the thin skin concept is not straightforward for several reasons. First, the effect of stimulation cannot be considered to be localized in an infinitesimal region near the wellbore. Second, even if an equivalent skin factor can be defined, it will not be constant during the transient period. Third, the negative skin does not allow for a rigorous solution of the transient problem in the presence of wellbore storage and hence type curves can be generated only using "equivalent" fractured well models.
In this paper we introduce a theoretically rigorous approach for the case when the effect of stimulation (or, as a matter of fact, damage) can be represented as a power-law variation of the permeability (as a function of the radial distance from the well). The well-reservoir system is described with three parameters: the areal average permeability, the power-law exponent (positive for damaged and negative for stimulated wells) and the wellbore storage coefficient. To our knowledge first in the technical literature, the model is solved rigorously in Laplace space. Using numerical inversion, type curves are generated. The interpretation methodology is illustrated with field cases.
Well Construction Efficiency Processes Yielding a Significant Step Change
Authors: Wylie Glenda , Zamora Frank , Terry Jim , Murali B. N. 
Published: December 2007

Abstract
In the past, serial drilling operations have been employed for the conventional well-architecture construction process. In this paper, new technological advancements from initial design planning to execution processes will be discussed. These advancements produce a "step-change" well architecture with a uniform well diameter and fullbore production delivery conduit called a monowell. From the well-construction processes to the "end" product, efficiency is driven in the technologies and processes described.
Technical improvements in mechanical and chemical solutions can help achieve a well architecture with a uniform diameter in reduced serial operations. Technological advancements in the areas of composite technology and realtime downhole monitoring can enhance deployment efficiency compared to conventional methods. The efficiency processes yield a well architecture with more efficient reservoir penetration and oil-production delivery by: Reducing formation/reservoir evaluation time and well placement through better methodsIncreasing penetration rateReducing the volume of drill cuttings and the oil content contained on the cuttingsReducing fluid requirements (i.e. drilling fluids and cements)Reducing casing size and the number of casing strings requiredReducing overall rig timeReducing overall flat timeImproving well productivityReducing required horsepower and rig size
The unique design and planning features of the monowell are discussed, including reservoir focus, geomechanics, and design requirements of drilling systems, formation evaluation equipment, fluid systems, and wellbore hardware. Multiple "uniform diameter" well-construction execution methods, including multiple deployment methods, are discussed. Together, the well-architecture change and execution-process changes result in a monowell with improved well construction design, execution, and production efficiencies. The monowell provides a significant industry step change in reducing cost per barrel of oil equivalent through improved efficiencies through a multitude of technologies.
Mass Transfer of Methane into Oil for the Transportation of Gas and Oil Through a Single-Phase Pipeline
Authors: Tang Joseph S , Zhang P. X. 
Published: December 2007

Abstract
Re-combining and transporting offshore produced gas and oil to onshore processing facilities through a single multi-phase pipeline is attractive for economic reasons. Multiphase pipeline is difficult to design and operate due to flow complexity, flow instability, uncertainty in liquid holdup and pressure drop; therefore, it has not been widely accepted in the industry. To avoid handling multi-phase problems, it is sometimes advantageous to operate the pipeline at above bubble point pressure so that gas can be re-dissolved into the oil and be transported in one phase. In addition, transportation of live oil with dissolved gas is a preferred option for waxy crude where gelling of the stock tank oil at reduced temperature is a problem. However, gas dissolution is not instantaneous because of finite mass transfer rate, a two-phase entrance region will exist, thus complicating the design of the pipeline. This paper studied the mass transfer characteristics of methane into light oil in a horizontal pipeline.
Depending on the Froude number and the gas-oil ratio, multi-phase flow can be characterized by three main flow regimes, namely, bubble, segregated and intermittent flow. Flow regime affects the interfacial contacting area as well as the mass transfer coefficient, thus the dissolution of gas into oil. Analytical solutions were derived to relate the rate of methane transfer into oil for the three flow regimes as a function of input gas-oil ratio, equilibrium GOR and pipe size. The model also predicted the length of the two-phase entrance region, i.e., the length required for complete dissolution of the gas. It was also found that inline mixing device was necessary to maintain dispersed flow for rapid transfer of gas into oil. The model agrees well with experimental results.
Optimization of Ramp-Up Operations in a Dual Large Diameter Long-Distance Subsea Wet Gas Pipeline System
Authors: Harun A. F. , Cochran S. W. , Choate T. G. A. 
Published: December 2007

Abstract
Ramp-up of large-diameter, long-distance production systems is challenging due to the large liquid holdups that can exist and the transient nature of ramp-up operations. This paper presents the results of multiphase simulations performed to optimize ramp-up operations in a subsea wet gas production pipeline system. All three phases (gas, condensate, and water) of the fluid system are considered. The pipeline system consists of dual interconnected, large-diameter (20+ in.) pipelines approximately 56 miles in overall length. The optimum ramp-up scenario is reached when the gas delivery rate can be increased in minimum time while maintaining the liquid surge within the onshore slug catcher liquid handling capacity. This paper proposes a solution to this problem and illustrates it with transient multiphase simulation results. The simulation results also provide some insight into the physics of the multiphase flow phenomena in large-diameter wet gas pipelines.
Resistivity Modeling of Array Laterolog Tools: An Application in an Offshore Norway Clastic Reservoir
Authors: Galli M. T. , Gonfalini M. , Mele M. , Belik P. , Faivre O. , Jammes L. , Litman A. 
Published: December 2007

Abstract
Resistivity logs, as directly used for the determination of Water Saturation profiles, have always been of focal interest for the oil industry; it's clear that the quality of these measurements, currently used in the net pay and hydrocarbon-in-place determination, must be very high. As a consequence, more accurate and flexible resistivity tools have been developed in recent years. We are addressing here the family of array tools, and especially the HRLA1, which makes available a set of 5 galvanic resistivity measurements at different depths of investigation.
Unfortunately, the most common types of environmental noise (borehole effects, shoulder bed resistivity contrasts, invasion, the presence of dips, anisotropy), still alter the measured resistivity, thus affecting the estimation of the true resistivity in hydrocarbon bearing levels.
In order to remove these alterations, Schlumberger, in cooperation with ENI-AGIP, has developed a 2D resistivity modeling & inversion technique that can simultaneously correct a number of environmental effects.
This paper presents the results obtained in two wells of a reservoir in the offshore Norway area where the sandstone bodies are interbedded with deltaic shales. The values of porosity and permeability are generally very high and a complete set of data (conventional & special core analysis, conventional wireline logs, microresistivity imaging logs, NMR, sedimentological analysis from core and images) is available.
The 2D modeling provided a better definition of the water saturation in the thinner sandstone bodies of the sequence and in the presence of anomalous invasion profiles.
When comparing the resistivity modeling results with those obtained by standard interpretation techniques, we can see the effectiveness of the developed methodologies (both hardware and software) in improving the reservoir characterization and in maximizing the return of the investments in logging and well data measurements.
Coupled Geomechanics and Reservoir Simulation
Authors: Thomas L. K. , Chin L. Y. , Pierson R. G. , Sylte J. E. 
Published: December 2007

Abstract
An iterative procedure is presented in this paper to couple geomechanics and reservoir simulation models for the simulation of weaker rock formations with complex constitutive behavior. Parallel computing is employed in the coupled model to reduce run time in the compute intensive geomechanics model. The procedures developed here are general and can be applied to any reservoir simulation and geomechanics model.
Field and example problems under a variety of exploitation scenarios are presented to demonstrate the utility and robust nature of the coupled model.
A Petrophysics and Reservoir Performance-Based Reservoir Characterization of the Womack Hill Smackover Field Alabama
Authors: Avila J. C. , Archer R. A. , Mancini E. A. , Haynes C. D. , Blasingame T. A. 
Published: December 2007

Abstract
The primary objective of this work is to perform a complete characterization of the Womack Hill (oil) Field in Southern Alabama using petrophysical and reservoir performance data — and to provide reservoir management strategies that lead to improved oil recovery at Womack Hill Field. The process for achieving this goal requires the following specific objectives: To develop correlations between the core and well log data in order to generate spatial distributions of reservoir properties such as: porosity, permeability, net pay, etc.To analyze the production history on a per well basis using the decline type curve technique which provides estimates of the following properties: —Oil-in-place (N),—Effective permeability (k),—Flow capacity (kh),—Reservoir drainage area (A), and—Near-well skin factor (5).To determine the Estimated Ultimate Recovery (or EUR) for each well using the historical production data. The EUR is used to establish the volume of recoverable oil-in-place.To draw conclusions and provide recommendations regarding infill drilling, well completions, and production practices based on the results of integrating the geological data and the production history analysis.
Improving Results of Coalbed Methane Development Strategies by Integrating Geomechanics and Hydraulic Fracturing Technologies
Authors: Johnson Raymond L. , Flottman Thomas , Campagna David J. 
Published: December 2007

Abstract
Hydraulic fracturing has been a key technology in the development of coalbed methane (CBM) resources worldwide. Obtaining adequate fracture length and conductivity has limited the ability to obtain adequate productivity improvement to further develop many small seams or stacked-seam reservoirs. Fracture complexity and growth out of the interval have frequently been cited as limiting factors in achieving optimal length in these types of intervals; however, the diagnostics to evaluate and model these effects have been limited. Finally, many of the past studies of hydraulic fracturing mechanics in coal have been focused on North American examples where normal faulting stress states are present, unlike many of the coal-producing basins worldwide and particularly in Eastern Australia.
Using examples from the Scotia Field, we describe how past and present stress framework analyses and post-frac treatment diagnostics were integrated to better describe the in-situ stress state. Through analyses of these examples, we qualify the inter-relationships of productivity to in-situ stress, pre-existing fractures, and observations from the induced hydraulic fractures. Finally, we describe cases where the hydraulic fracturing complexity and in-situ stress conditions lead to wellbore complications and observable rock-mechanical failures. The end result is a more predictive model, which is being used to develop this CBM resource.