bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Flow Modeling: The Fusion of Geophysics and Reservoir Engineering
Authors: Pagano Theodore A. , Fanchi John R. , Davis Thomas L. 
Published: December 2007

Abstract
The application of three-dimensional (3D), time-lapse seismic monitoring is rapidly becoming a prevalent tool in the oil and gas industry. Time-lapse seismic monitoring can dramatically improve reservoir understanding and consequent ultimate recovery factors. However, 4D seismic monitoring is not applicable to all reservoirs and all development strategies. A strong 4D seismic candidate must not only have favorable geophysical rock properties, but must also have a development plan that encourages observable changes in repeat 3D seismic surveys. A traditional flow simulator that includes a petrophysical model has the ability to predict ‘dynamic’ reservoir changes and the resultant changes in seismic response. This inter-discipline approach to reservoir modeling blurs the distinction between geophysics and reservoir engineering. This ‘integrated flow model’ is a powerful tool that can be used to determine the feasibility of a 4D seismic monitoring project before initiation. In addition, it can be used throughout the life of the monitoring project to ensure a correct and thorough understanding of the reservoir as it matures.
Integrated Approach to Infer Fractures and Manage the Waterflood Projects in Mauddud Reservoir, Raudhatain & Sabiriyah Fields, North Kuwait
Authors: Al-Ajmi Hussain Zayed , Chetri Hom Bahadur 
Published: December 2007

Abstract
Mauddud limestones are multi-billion barrel depletion drive reservoirs undergoing massive development efforts with a planned 700% increase in oil production through pattern waterflood. The conceptual development plan for the reservoir, in view of uncertainty about the degree of fracturing and its resultant impact, has been kept flexible allowing for a change in development strategy, if deemed necessary.
A review of the performance of historical offtake points and data acquired so far illustrates a large variation in static and dynamic behavior areally as well as vertically. Integration of multi-source evidences to describe the anomalies and infer the probable existence of fractures is done to predict the impact on the inverted 9-spot waterflood patterns likely to be operative next year. The integrated approach illustrates the significance of fluid & rock data, Pressure-Production data and information obtained from new & old logs to revisit the reservoir description for inferring fractures.
Recently acquired 3-D seismic data exhibited faults of various magnitudes scattered over the major area of historical offtake. The spread of cumulative production, well PI and Qmax areally revealed a linkage between the faulted & non-faulted area. A review of past PBU data coupled with core data further indicated the existence of fractures. A review of resistivity and caliper response in old logs and interpretation of image logs also deciphered the presence of fractures. Scanning through the drilling and completion histories of wells was done to authenticate the inferred fractures in Mauddud reservoir. The performance of the two waterflood pilots in operation was also reviewed to see areal and vertical connectivity utilizing the Pressure-production and RFT/PLT data to infer any flow through the fracture system.
Preliminary studies indicate that 7 inverted nine spot patterns (one-fourth of the total number of patterns) are likely to be impacted by the fractures due to premature breakthrough of water injected and reduction in the sweep efficiency. Analytical methods indicate the loss in recovery to the extent of 12 to 18% if significant fractures are present within the patterns. However, in case of minor degree of fracturing, Injectivities and sweep efficiency may improve.
In light of uncertainties on extent of fracturing, future work plan includes review of core, Image logs & productivity/Injectivity data from new wells and Pressure Build up data gathering with bottom hole shutting- in in key wells.
The integrated approach has helped to understand the flow dynamics of injected water better and recommendations leading to better management of the water injection project for Mauddud reservoir.
An Investigation of Three-Phase Counter-Current Flow Using X-Ray Computerized Tomography and Neuro-Simulation Modeling
Authors: Al-Wadahi M. , Grader A. S. , Ertekin T. 
Published: December 2007

Abstract
This work examines the physics of three-phase counter-current fluid flow driven by gravity and capillary transport mechanisms through a combination of experimental measurements and neuro-simulation modeling. There have been only a few scientific reports in the literature addressing counter-current flow phenomena, especially under three-phase flow conditions. Counter-current flow driven by gravity and capillarity may occur in fractured reservoirs (both in matrix and fractures), in solution gas drive and gas cap reservoirs with high vertical permeability, and in some water-flooding operations.
Three-phase flow experiments were conducted with an idealized system and the temporal and spatial saturation distributions during counter-current flow periods were acquired using computerized tomography. The experimental results were simulated using a conventional reservoir simulator. The simulation results provided the basis for training an artificial neural network through which the best relative permeability and capillary pressure functions that match the experimental data were obtained using a pattern recognition protocol.
Laboratory Based Evaluation of Gas Well Deliverability Loss Due to Waterblocking
Authors: Kamath Jairam , Laroche Catherine 
Published: December 2007

Abstract
Waterblocking due to invasion of completion fluids has been suspected to reduce gas well deliverability.1–5 However, this effect has not been quantified. We report results of a laboratory program to measure the waterblocking effect in core samples from a gas field. These data were mapped to a wellbore model to make deliverability predictions.
The laboratory data consist of gas flow rate as a function of injected gas pore volume for various liquids (brine, methanol, toluene, isopropyl alcohol, and brine-methanol mixtures) at two saturation states (fully saturated with liquid, and containing liquid and trapped gas). We injected over 10 000 PV of gas in each test to mimic near well bore conditions. The data showed that the liquid displacement regime was followed by a mass transfer regime.
The wellbore model had a time varying skin to account for the cleanup of the fluid invaded ("waterblocked") region. Clean up occurs as gas flows past this high liquid saturated region and removes liquid by displacement and mass transfer. We used the laboratory data to relate the reduced permeability of this region to pore volumes of gas throughput.
We find that any loss in gas well deliverability recovers in two phases. The first phase corresponds to fluid displacement ("flowback period") and lasts for a few days at most. The second phase is slower and can last several months. Here evaporation causes the deliverability to slowly increase. It is in this regime that adding volatile fluids, such as methanol, to the completion brines has advantages.
Fracture Pressure Slope Analysis for TSO’s in High-Permeability Formations
Authors: Smith Jeffrey E. , Meyer Bruce R. , Jacot R. Henry 
Published: December 2007

Abstract
The relative popularity and success of the frac & pack technique in hydraulic fracturing has resulted in some misconceptions regarding the objective, procedure and pressure analysis after a screen-out. This paper addresses frac & pack procedures and the pressure response after a tip screen-out (TSO).
An analytical method has been developed for analyzing pressure slope behavior after a TSO in high permeability formations. These equations incorporate the first order parameters affecting the fracture pressure, rate of change of pressure (derivative) and pressure slope behaviors after a screen-out.
The fundamental equations for pressure slope analysis are similar to those originally developed by Nolte for pressure decline analysis. The major difference is that after the fracture stops propagating (i.e., after a TSO) the injection rate is not zero. Consequently, if the injection rate is greater than the leakoff rate, the fracture volume and net pressure (constant compliance) must increase. If the injection rate falls below the leakoff rate, the fracture net pressure must decrease.
Although analytical equations will not replace three dimensional fracturing simulators normally used for design and realtime history matching, they do provide insight into the major parameters affecting pressure behavior after a TSO without running a numerical simulator. The analytical equations presented in this paper demonstrate why pressure slopes after a screen-out are typically much greater than unity for low efficiency fractures.
A generalized set of equations is presented for analyzing the pressure slope behavior after a screen-out. Numerous graphs are provided which illustrate the parametric effects of fracture efficiency, spurt loss and fracture net pressure at the time of a screen-out on the pressure, derivative and slope behaviors after a TSO. Comparisons of the analytical pressure slope equations with a three dimensional fracturing simulator are presented to show the application of the analysis.
A new methodology of frac & pack post analysis is presented using the pressure slope technique. This methodology utilizes the pressure slope during a screen-out as a check on the minifrac and fracture efficiency. Two frac & pack cases with bottomhole data are analyzed using a three dimensional hydraulic fracturing simulator to illustrate the pressure slope analysis for low efficiency fractures.
Three-Dimensional Calculation and Visualization of Fault Gouge Ratio
Authors: Hoffman Karen S. , Neave John W. 
Published: December 2007

Abstract
Understanding the sealing characteristics of faults is critical in assessing the hydrocarbon potential of traps formed by faults. Fault gouge ratio and juxtaposition analysis have often been limited to a single cross section (a two-dimensional approach) or to a single, isolated fault surface (a partial three-dimensional approach). We have now developed a full three-dimensional solution for calculating fault gouge ratio. This method uses a continually varying clay volume fraction, a network of faults (isolated, dying and/or branching), and displacement along the fault surface (instead of just the dip component). The structural model used as the framework for this calculation is based on geometric reconstruction techniques that construct faults and horizons in three-dimensional space, allowing easy and rigorous calculation of juxtaposition and displacement. These last two items are necessary input to the fault gouge ratio calculation.
The steps in calculating fault gouge ratio in three-dimensional space are as follows: (1) create structural framework, (2) calculate volume of clay (Vcl) as a continually varying property within this structural framework, (3) determine displacement, allowing for oblique slip, and (4) calculate fault gouge ratio for hanging wall and foot wall blocks, and sum to determine the ratio for every point on the fault
Rigorous calculation of fault gouge ratio depends on a robust structural model. With the model described herein, a variety of scenarios may be investigated, thus incorporating uncertainty into the calculation. Determining whether a fault will act as a seal, or whether there is potential for development of leaks during the production of the reservoir depends on many variables. Minimizing the uncertainty in this part of the analysis may provide increased confidence in assessing risk.
NMR Logging Improves Wellsite Efficiency, Completion Decisions, and Formation Evaluation in a Freshwater, Shaly Reservoir
Authors: Moraes Jose-Jorge , Brandao Renilton , Tellez Ricardo , Vallejo Jaime , Garcia German , Singer Julian 
Published: December 2007

Abstract
Rio Ceibas is a freshwater shaly reservoir in the Honda formation of Colombia. A typical well has 15+ sands, which may contain light oil, medium oil or mobile water. Formation evaluation is difficult. The fresh water and the high volume of smectite clay cause resistivity logs to respond more to the volume of clay than to the difference between oil and water. Nuclear measurements do not indicate clearly the most productive intervals. A focused effort was started in 1998 to increase production using cost-effective modern technology, one element of which was the introduction of nuclear magnetic resonance (NMR) logs.
At the wellsite, NMR permeability is used to choose points for wireline pressure tests. The percentage of dry tests has been reduced from 24% to 7%. This saves significant rig time since pressures must be monitored regularly in many sands. As verified on cores, the presence of an NMR signal with T2 &gt; 300ms is a sign of light hydrocarbons. When other data are inconclusive, this indicator helps to decide whether to perforate a sand. NMR free fluid and permeability are then used to decide which intervals in the sands have the best producibility. This method saves costs by reducing perforating intervals without reducing production.
For reservoir description, NMR has contributed to improved estimates of effective porosity, and qualitative permeability. Both cores and logs have been analyzed to establish interpretation parameters such as bound- and clay- water cutoffs, and permeability coefficients. In those sands that produce clean oil, the irreducible water from NMR logs is an indicator of water saturation, because of the difficulty of obtaining a reliable value from conventional logs. It is also used to determine resistivity interpretation parameters for calculations in other sands. The new formation evaluation procedure improves the match between predicted and actual production.
Correlations of NMR Relaxation Time with Viscosity, Diffusivity, and Gas/Oil Ratio of Methane/Hydrocarbon Mixtures
Authors: Lo Sho-Wei , Hirasaki George J. , House Waylon V. , Kobayashi Riki 
Published: December 2007

Abstract
Viscosity, diffusivity, relaxation time and gas/oil ratio are important properties in the characterization of reservoirs by NMR well logging and in prediction of production performance. For the past few years, NMR well logging has been used to estimate the formation properties and hydrocarbon liquid/vapor characterization. Previous work has shown that pure alkanes, alkane mixtures, viscosity standards and stock tank crude oils have NMR relaxation times which vary linearly with viscosity/temperature and diffusivity on a log-log scale. However, pure methane at some temperatures and pressures does not follow the same trend. Thus, the linear correlation may not be valid for live crude oils that contain significant amount of methane. Therefore, the study of methane-hydrocarbon mixtures is of interest.
An NMR spectrometer equipped with a high-pressure probe was used to study the relationship between NMR T relaxation time and viscosity/temperature, diffusivity and gas/oil ratio of methane-hydrocarbon mixtures. Relaxation time and diffusivity measurements of three mixtures were made, methane-n-hexane, methane-n-decane and methane-n-hexadecane. It was found that unlike stock tank oil, relaxation times do not depend linearly on viscosity/temperature on a log-log scale. Each of the mixtures forms a different curve. Generalized correlations between viscosity, diffusivity, gas/oil ratio and NMR relaxation times were developed. First, the relaxation time mixing rule was developed by studying the theory of NMR relaxation mechanism. From the mixing rule, it was found that departure of relaxation times of methane-n-alkane mixtures from linear correlations on a log-log scale can be correlated with the proton fraction of methane, expressed as gas/oil ratio. Thus, correlations between relaxation time, viscosity/temperature and gas/oil ratio were developed. Correlations between relaxation time, diffusivity and gas/oil ratio were also developed. There is a linear relation between diffusivity and viscosity/temperature that is independent of composition. From these correlations, viscosity and gas/oil ratio can be estimated from NMR T1 relaxation time and diffusivity.
Viscous-Elastic Polymer Can Increase Microscale Displacement Efficiency in Cores
Authors: Wang Demin , Cheng Jiecheng , Yang Qingyan , Gong Wenchao , Li Qun 
Published: December 2007

Abstract
When flooding with viscous Polymers, due to the increase in viscosity and decrease in permeability (for polymers that absorb on the rock surface), the mobility ratio compared to water flooding becomes more favorable. Therefore the volumetric sweep efficiency increases and the recovery of the reservoir on a macro scale increases also.
Most people think that polymer flooding does not increase the recovery at a micro scale. But numerous results in this work do not support this conclusion. From cores in the lab, the effect of flooding with viscous-elastic polymers on different types of residual oil after water flooding was studied. The different types of residual oil are: 1) oil film on the rock surface; 2) oil in "dead ends"; 3) oil in pores throats retained by capillary forces; 4) oil un-swept in micro scale heterogeneous portions of the core. It could be seen that all types of micro-scale residual oil were reduced after flooding with viscous-elastic polymers.
Due to the elastic nature of the polymer, the velocity distribution in the pores are quite different from Newtonian Fluids and the polymer could also exert a very strong "pulling effect" on different types of residual oil. The study pointed out that the relationship between Capillary Number and Recovery of cores for Newtonian Fluids does not apply to fluids with elastic properties.
In the study, it was seen that the increase in micro scale recovery was related to the elastic properties of the polymer fluids. Different polymer fluids had quite different elastic properties. Some had practically no elasticity. Therefore, when selecting polymers for flooding, its elastic properties must be considered. The difference in incremental recovery can be more than 6 % OOIP (original oil in place), which is substantial, it can make a polymer flood successful (both technically and economically) or not.
The above conclusions can also be confirmed by pressure coring data and field results of large scale polymer (PAM) flooding in Daqing Oil Field, which is obtaining an incremental oil recovery of more than 13% OOIP. This magnitude of incremental oil recovery can not be explained by just an increase in volumetric sweep efficiency.
The above conclusions 1) can explain why some polymer floods were successful or not; 2) should be considered when selecting polymer floods and, 3) should be able to increase the incremental oil of future polymer floods.
The rheology of viscous-elastic fluids in porous media is very much different from fluids with no elasticity. Much work needs to be done in this field. Many conclusion obtained by studies on Newtonian Fluids need to be re-assessed when used on visco-elastic fluids.
Development of a New Sand Control Technique - Phase I: Laboratory Development
Authors: Aggour M. A. , Abu-Khamsin Sidqi A. , Osman E. A. 
Published: December 2007

Abstract
This paper presents the results of the laboratory development phase of a major project to develop a novel sand control technique that could overcome the technical and economic limitations associated with existing methods of sand control. The novel technique is based on in-situ sand consolidation by low-temperature oxidation of a hydrocarbon fluid that saturates the sand around the wellbore. Laboratory development consisted of two stages. In the first stage, the various process-controlling parameters were studied to determine the optimum conditions that yield consolidated sand with the highest possible compressive strength, minimum loss of permeability, and high stability against typical formation and workover fluids. Under the developed optimum consolidation conditions, it was possible to produce consolidated sand, from originally loose sand, that retained between 86.4% and 95.5% of its original permeability, was completely stable against flow of crude oil, water and mud acid, and had a compressive strength between 1,800 and 2,300 psi. In the second stage, the feasibility of field application of the process was demonstrated on a full-scale model resembling an 8-ft. section of a 7 in. cased well. The model was packed with loose sand and saturated with brine. The resulting consolidated sand around the casing was tested by flowing back at a rate of 44 bpd/ft. (the maximum available pump apacity) without any sand production. Plans are underway for the first field implementation of the process.
How the 3D Modeling Could Help Hole-Cleaning Optimization
Authors: King I. , Trenty L. 
Published: December 2007

Abstract
The development of complex wells with deviated and long horizontal sections induce hole cleaning and cuttings transport problems. A better knowledge of the mechanisms controlling the cutting evacuation is therefore necessary. This paper presents a three dimension numerical approach which has been developed to improve the understanding of the drilling mud flow behavior in the annulus. The influence of drilling parameters is pointed out. The way a settled cutting bed could modify the flow is also analysed. To go further in the drilling process modeling, cuttings have been introduced in the mud flow, with the same 3D approach. All this methodology allows to define critical drilling configurations for the cutting removal, and therefore will help to provide criteria for hole cleaning optimization.
Accounting for Seismic scale in Stochastic Reservoir Simulations Constrained by Seismic Data
Authors: Gilbert F. , Joseph C. H. 
Published: December 2007

Abstract
Integrating seismic data in 3D reservoir property simulations leads to more accurate reservoir models. But the difference of scale between both data should be taken into account. For that, seismic data are usually considered as 2D information, hence related to the vertically averaged reservoir property; this implies that the seismic scale (or resolution) is identified to the reservoir thickness, i.e. to some user-defined size independent of the actual seismic volume support. In this context, we propose a methodology which takes into account a more realistic 3D seismic volume support. This methodology calls first for the determination of the 3D volume support of the seismic data by looking at seismic variograms or at the seismic signal. Then, a two-step simulation methodology is applied. In Step 1, the reservoir property cube at seismic scale (i.e., on the seismic volume support) is estimated from the seismic data. In Step 2, the resulting estimated cube is used for constraining the Sequential Gaussian Simulation (SGS) of the reservoir property (at point scale) either through cokriging of data at different scales or through non stationary kriging. An application of this methodology is presented: porosities are simulated at one reservoir level, constrained by a 3D impedance cube after inversion. Results of both Step 2 alternatives are compared in terms of input reproduction, easiness of implementation, computing time, impact of the seismic data,…