bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Structural and Stratigraphic Analysis Using Subsurface Residual Anomaly Maps: Case Study From Arabian Platform
Authors: Al-Qahtani AbdulMotaleb , Al-Muzaiyen Emad 
Published: December 2007

Abstract
In Arabian Platform, tracing the sequential development of geological structures is often a challenging task due to the activity of multiple tectonic events throughout its geologic history. Originalstructures have not yet been reconfigured during the Paleozoic and Mesozoic, leaving long and complex growth histories. To unravel the development of these structures, analysis of isopach maps at specific structural events must be considered.
The following study was undertaken in an effort to reconstruct the development history of the Arabian Peninsula. Several different residual growth analyses were performed to answer questions regarding the timing of the growth of the structure, and the mechanisms responsible for the location and shape of the structure. General interpretations of several seismic lines provided information about the location and trend of a basement level fault that exists directly underneath Arabian Platform sedimentary section. Detailed interpretation of residual growth maps reveals regional NW-SE and N-S major faults, characteristic of compression and strike-slip geometry associated with Hercynian Orogeny. In addition to gravity and magnetic data, structure and isopach maps constructed from several hundred wells and thousands of 2D seismic data throughout Arabian platform help to constrain the aerial extent of basement structure and sedimentary facies distributions overlying basement structures.
Residual growth maps were computed to identify growth related thinning and subsidence thickening which will be correlated with features seen in the seismic data. Results of the above analyses demonstrate that the Arabian Platform has a long growth history, beginning as early as Pre-Cambrian time, and continuing through the Middle to Early Tertiary
Innovative Well-Testing System for High-Rate Sour-Gas Khuff Well in the North Field, Qatar
Authors: Al Hajri M. , Macdonald B. , Marcellin P. , Segui E. 
Published: December 2007

Abstract
This paper presents the innovative system designed by Dolphin Energy to production test the Khuff intervals of the North Field data well NFD1-1. The design comprised the use of a single run of a 4 ½" tubing test string with a Down Hole Safety Valve (DHSV), production packer, acoustic surface read out gauges, and 10K Xmas-tree to achieve the test objectives.
The through tubing zonal isolation technique allowed the sequential testing of the Khuff reservoir intervals without the use of a kill fluid and removal of the test string between tests. Thus reservoir damage was minimized, and recovery of initial productivity more likely for future development.
The test string design enabled the optimization of the flow and shut in periods to ensure full and quality data gathering. The flexibility of the design also allowed additional intervals to be perforated and tested.
All components operated continuously during the seven separate tests of the four Khuff zones over a period of 64 days.
NMR Petrophysics in Thin Sand-Shale Laminations
Authors: Minh Chanh Cao , Sundararaman Padmanadhan 
Published: December 2007

Abstract
We use nuclear magnetic resonance (NMR) logging to help with the petrophysical evaluation of thin sand-shale laminations. NMR helps to 1) detect thin beds, 2) determine fluid type, and if hydrocarbon is present, 3) establish the hydrocarbon type and volume, and finally 4) determine the permeability of the sands (as opposed to that of the sand-shale system).
Formation evaluation in thin sand-shale laminations starts with their detection. NMR vertical resolution is mainly controlled by the antenna aperture, that is, in the case of a high-resolution antenna, 6 in. or 15 cm. Within that distance NMR tools will cumulatively measure all layers of shales and all layers of sands regardless of their individual thicknesses. Because NMR relaxation time in shales is much faster than in the productive sands, thin sand-shale laminations appear on NMR logs with the characteristic bimodal relaxation distribution.
The thin laminations are often below the resolution of conventional logs that have a typical vertical resolution of 6 to 12 in. or 15 to 30 cm. This makes fluid typing in the centimeter-thick sands problematic from conventional logs. Also, formation pressure or sampling tools could hit-and-miss the thin sands. In contrast, since gas, oil, and water have different properties, fluid typing techniques that exploit all NMR relaxation times (T1 and T2) and diffusion (D) offer new ways to determine the fluid type in thin layer sands.
From the bimodal relaxation distribution of the laminated sand-shale system, it is often possible to determine a cutoff to separate the two components. Porosity in the sand component can then be estimated separately and with it the hydrocarbon pore volume.
Conventional high-resolution permeability from NMR is limited to one antenna aperture. If the sand layer thickness is less than that distance, the determined permeability of the sand-shale system will underestimate the true permeability of the sands. Using a fluid flow model, we show that the permeability of the sand component can be estimated separately.
Experiments were conducted to verify the characteristic NMR bimodal relaxation distribution in thin beds, and to investigate whether the fraction of sand/shale and the sand porosity could be determined from NMR logs. The results confirmed observations on logs, of which we show case examples of thin sand-shale laminations that are water-bearing, oil-bearing, and gas-bearing respectively. In each case the NMR detection was verified against imaging logs, and the fluid type in the sands was determined from multi-dimensional NMR analysis. The derived hydrocarbon volume was then compared with the results estimated from a full triaxial (3D) induction tool. Permeability of the sand layers was also computed and compared to that of nearby thick sands. Core data in one well was used to validate NMR detection, porosity, permeability and net sand thickness.
PI-Mode Production Over Bottomwater
Authors: Wang Y. , Laine E. , Ehlig-Economides C. A. 
Published: December 2007

Abstract
Over bottom water, a horizontal well will usually perform better than a vertical well because the oil-water contact rises in the shape of a crest instead of a cone. Analytical models have predicted greater critical rates for horizontal wells and greater recovery at water breakthrough when the horizontal well is produced at higher than the critical rate. However, as with vertical wells, horizontal wells may water out before getting an economically sufficient recovery factor. The objective of this paper is to evaluate the strategy of waterflooding over bottom water using the π-mode production strategy.
The objective of π-mode production is to accelerate recovery and achieve 50% recovery efficiency in less than 5 years through waterflooding. This is accomplished by production at a constant oil rate and full voidage replacement through reinjection of produced water. As in previous work, this paper employs the horizontal well couplet with one injector and one producer. Simulations reported in previous studies have demonstrated the feasibility of this waterflood strategy, first for homogeneous and then for heterogeneous reservoirs. This paper determines when the π-mode production strategy is effective over bottom water. In addition, the π-mode production strategy is compared to an array of horizontal well production wells without injection.
Simulations performed for a variety of well spacing, different reservoir thicknesses, different mobility ratios, and different aquifer sizes are compared for recovery and net present value versus time for both the π-mode production strategy and production well strategies. Results quantify optimal well spacing and show that the π-mode production strategy is effective over small aquifers while production wells without injection work better for large aquifers.
Subsurface Integrated Production Systems
Authors: Rivas Olegario 
Published: December 2007

ABSTRACT
When considering the potential for developing marginal fields, the high cost associated with conventional production facilities becomes a major consideration for financial viability.
Conventional oil and gas production facilities are very costly and time consuming to fabricate. Since oil production cannot begin without permanent production facilities in place, production revenue is often delayed while waiting for these facilities to be completed.
Basically, conventional oil and gas production facilities involve a production/test manifold, gas/oil separation system, storage tank, pumping system, and auxiliary systems (e.g., chemical injection, dehydration system, etc.).
This paper presents an alternative to conventional oil and gas production facilities. The alternative integrates these functions into one system. Based on fluid capacity requirements, the subsurface integrated production system (SIPS) concept can be configured for single (SIPS-S) or multiple (SIPS-M) installations. The dimensions of SIPS applications take into account sufficient volume for the storage of produced fluids and offer extended residence time for natural separation of wellbore fluids.
According to the required separation capacity, the wellbore fluids may be separated in the SIPS units by gravity or separation may be enhanced by the use of mechanical separating devices.
This concept includes the use of at least one electrical submersible pump (ESP) for moving the stored liquid from the collection well to a remote location, completing a basic SIPS. The separated gas is conveyed from the SIPS to the required end user.
Induced Fracturing in Reservoir Simulations: Application of a New Coupled Simulator to Waterflooding Field Examples
Authors: Hustedt B. , Zwarts D. , Bjoerndal H.-P. , Masfry R. , van den Hoek P. J. 
Published: December 2007

Abstract
Water-injection induced fractures are key factors influencing successful waterflooding projects. Controlling dynamic fracture growth can lead to largely improved water management strategies and potentially to increased oil recovery and reduced operational costs (well count and water treatment facilities reduction), thereby enhancing the project economics.
The primary tool that reservoir engineers require to guarantee an optimal waterflood field implementation is an appropriate modeling tool that is capable of handling the dynamic fracturing process in complex reservoir grids.
We have developed a new modeling strategy that combines fluid-flow and fracture-growth in one reservoir simulation. Dynamic fractures are free to propagate in length- and height-direction with respect to poro- and thermo-elastic stresses acting on the fracture. A prototype simulator for contained fractures was successfully tested.
We have extended the coupled simulator to incorporate non-contained fractures. The new simulator handles fracture length and height growth by evaluating a fracture propagation criterion that is based on a Barenblatt condition. The solution of the five-dimensional problem is computed using a tuned Broyden approach.
We demonstrate the capabilities of the coupled simulator by showing its application to a complex reservoir simulation model. The fracture modeling is used to history match an injectivity test in a five-spot injection pattern using produced water. The coupled simulation results and the field data interpretation show a very good match. The outcome of the injection test led to an appropriate waterflood management strategy adapted to the specific reservoir conditions and, in terms of production, in a net oil production increase of 50-100%. The field example shows how the coupled simulator technology can be used to achieve optimized waterflood management strategies and increased oil recovery.
A Multistage Sampling Method for Rapid Quantification of Uncertainty in History Matching Geological Models
Authors: Ma X. , Al-Harbi M. , Datta-Gupta A. , Efendiev Y. 
Published: December 2007

Abstract
The paper presents a novel method for rapid quantification of uncertainty in history matching reservoir models using a two-stage Markov Chain Monte Carlo (MCMC) method. Our approach is based on a combination of fast linearized approximation to the dynamic data and the MCMC algorithm. In the first stage, we use streamline-derived sensitivities to obtain an analytical approximation in a small neighborhood of the previously computed dynamic data. The sensitivities can be conveniently obtained using either a finite-difference or streamline simulator. The approximation of the dynamic data is then used to modify the instrumental proposal distribution during MCMC. In the second stage, those proposals that pass the first stage are assessed by running full flow simulations to assure rigorousness in sampling. The uncertainty analysis is carried out by analyzing multiple models sampled from the posterior distribution in the Bayesian formulation for history matching. We demonstrate that the two-stage approach increases the acceptance rate, and significantly reduces the computational cost compared to conventional MCMC sampling without sacrificing accuracy. Finally, both two-dimensional synthetic and three-dimensional field examples demonstrate the power and utility of the two-stage MCMC method for history matching and uncertainty analysis.
Optimal Waterflood Management Using Rate Control
Authors: Alhuthali A. H. , Oyerinde D. , Datta-Gupta A. 
Published: December 2007

Abstract
Field scale rate optimization problems often involve highly complex reservoir models, production and facilities related constraints and a large number of unknowns. All these make optimal reservoir management via rate and flood front control difficult without efficient optimization tools. Some aspects of the optimization problem have been studied before using mainly optimal control theory. However, the applications to-date have been limited to rather small problems because of the computation time and the complexities associated with the formulation and solution of adjoint equations. Field-scale rate optimization for maximizing waterflood sweep efficiency under realistic field conditions has still remained largely unexplored.
We propose a practical and efficient approach for computing optimal injection and production rates and thereby manage the waterflood front to maximize sweep efficiency and delay the arrival time to minimize water cycling. Our work relies on equalizing the arrival times of the waterfront at all producers within selected sub-regions of a water flood project. The arrival time optimization has favorable quasi-linear properties and the optimization proceeds smoothly even if our initial conditions are far from the solution. Furthermore, the sensitivity of the arrival time with respect to injection and production rates can be calculated analytically using a single flow simulation. This makes our approach computationally efficient and suitable for large-scale field applications. The arrival time optimization ensures appropriate rate allocation and flood front management by delaying the water breakthrough at the producing wells.
Multiple examples are presented to support the robustness and efficiency of the proposed optimization scheme. These include several 2D synthetic examples for validation purposes and a 3D field application. In addition, we demonstrate the potential of the approach to optimize the flow profile along injection/production segments of horizontal-smart wells
Using Microseismic Monitoring and Advanced Stimulation Technology to Understand Fracture Geometry and Eliminate Screenout Problems in the Bossier Sand of East Texas
Authors: Baihly J. , Laursen P. , Ogrin J. , Le Calvez J. H. , Villarreal R. , Tanner K. , Bennett L. 
Published: December 2007

Abstract
A major factor to determine the effectiveness of any tight gas stimulation program is to understand the hydraulic fracture geometry. Technology has progressed to the point that microseismic monitoring of hydraulic fracture treatments can provide key information to characterize fracture development.
At the onset of this stimulation project, in-depth knowledge of reservoir, completion, production, geophysical, and geological engineering were integrated to determine the solution. The integration of these domains of expertise led to project success.
The results presented within are from a series of hydraulic fracture stimulations in the Bossier Sand formation where field-wide screen-out problems were historically observed. This paper documents the integrated process utilized to solve the screenout problem as well as to establish a way forward to achieve optimized completions in the target sand.
Within the course of this project, microseismic monitoring coupled with sound fracture engineering technology led to several observations. a) The original design was not contained in the target sand. b) Microseismic monitoring and computer model simulation using calibrated stresses confirmed undesired fracture development uphole. c) Microseismic monitoring confirmed formation micro-imager log based fracture azimuth determination.
This integrated study led to improved completion designs which resulted in hydraulic fractures contained within the target sand and a plan for an infill drilling pattern to optimize field drainage.
Water Injection Optimization Using Historical Production and Seismic Data
Authors: Huang Xuri , Ling Yun 
Published: December 2007

Abstract
This work proposes a method to optimize waterflooding by using production and time-lapse seismic data. Using time-lapse seismic difference as an indication of inter-well influence, inter-well connectivities or influence functions are determined using a combinatorial algorithm (stochastic hillclimbing) by constraining the computation with time-lapse seismic. The water-cut is estimated using a fitting function. By perturbing the injection rate in the injectors, the oil production is optimized. The field in this study is mature with 15 years of production history and with 70% water-cut at the present time. Two legacy repeated seismic surveys, of in 1991 and 2001 vintages respectively, are reprocessed to enhance the repeatability from the original data. The reprocessing is done to eliminate the survey, source and noise differences. The connectivity or influence function is estimated using a window of balanced flooding. It is found that seismic constraining for the connectivity calculation increases the consistency of the inter-well relationship with the spatial data. In order to have an operational waterflooding scheme, a multiple realization approach is used. That is, the optimized injection is randomly perturbed under specified upper and lower bounds. The production rate is computed using the inter-well influence function. It is found that the optimal injection configuration can increase oil production. With a pilot implementation, it is shown that the new injection scheme can delay the oil production decline.

Introduction
Optimization of water-flooding is a critical process for reservoir management. Generally, the optimization can be conducted through an adjustment of the injection pattern or injection scheduling by reservoir simulation or by intuitive analysis. However, to perform this process, the injector-producer relationship or inter-well relation needs to be understood. To understand this relationship, the production history data are normally used either through a correlation or material balance-type analysis. For example Soeriawinata et al. used a correlation approach to build the injector-producer relationship.1 Jansen used a wavelet transform to analyze the inter-well relationship using producer-injector data.2 Albertoni et. al. proposed an approach of linear regression using injector-producer production history data.3,4 For quantitative analysis, reservoir simulation can be used with even seismic data in the process of history matching.5 However, reservoir simulation is quite time-consuming. On the other hand, using the production history sometimes has difficulties to fully account for the spatial heterogeneity. It would be critical to incorporate the production history data and other data such as seismic to analyze the producer-injector relationship. In this work, we propose using the time-lapse seismic attributes to constrain the estimation of the injector-producer relationship.
Scale Inhibitor Squeeze Treatments Deployed From an FPSO in Deepwater Subsea Fields in the Campos Basin
Authors: Bogaert P. , Berredo M. C. , Toschi C. , Jordan M. M. , Frigo D. M. , Morgenthaler L. , Afonso M. 
Published: December 2007

Abstract
This paper describes field experience and lessons learned from scale-control operations in a deepwater subsea development in the Campos Basin, Brazil; specifically, from bullheading scale-inhibitor squeezes from the FPSO host, along the production flowlines, into four low-watercut, horizontal subsea wells, completed with sand control.
The relatively small number of high-cost, highly productive wells, coupled with a very high barium-sulfate scaling tendency upon breakthrough of injection water, meant not only was effective scale management critical to achieve high hydrocarbon recovery, but even wells at low water cuts were deemed to be at sufficient risk to require squeeze application.
Use of conventional, water-based squeezes have been known to cause significant damage to productivity in low-watercut wells, including those showing a fines-migration tendency, as was the case here. Hence, based upon risk mitigation, supported by an extensive programme of laboratory testing, it was decided that for the initial treatments only the mainflush would be water-based, with a mutual-solvent preflush and marine-diesel overflush.
Other key challenges associated with treating from the host included the remote location of the wells, the potential to form hydrates, the cleanliness of the lines along which the treatment would pass, the achievement of effective placement over a long producing interval, as well as the need to deploy the chemical package via a support vessel adjacent to the FPSO. All had to be managed due to the high cost and low availability of a deepwater rig that could deploy the treatments directly to the subsea wellheads.
The paper will explore in detail the issues associated with inhibitor-squeeze deployment in deepwater, subsea fields, many of which are currently being developed in the Campos basin, Gulf of Mexico and West Africa, and is a good example of best-practice sharing from another oil basin.
Structuring Surface Production Networks To Reduce Development Cost
Authors: Xiao J. J. , Al-Muraikhi A. J. , Shammasi M. 
Published: December 2007

Abstract
In the development of a new field, after the surface well locations are determined, the next question that needs to be addressed then is how to structure the surface production network in a cost effective manner. In an offshore field development, a similar question is how to link productions from several satellite platforms and bring production onshore.
In this paper, we present a production network layout tool which allows the determination of 1) a centrally located manifold or separation facility site, and 2) an optimal network structure that minimizes material (pipeline length) usage. The manifold or processing facility location is chosen to minimize load-distance from all the wells. This ensures less pressure loss and shorter pipe usage. The production network is structured to reduce total pipeline length and at the same time meet wellhead flowing pressure requirements and flowline erosional velocity constraints. An example case is used to illustrate the value of the tool.