bluuebunny/crossref_metadata_2025_split huggingface dataset:
Induced Nuclear Reaction Logging
Authors: Hoyer W.A. 
Published: June 2014

Abstract
A pulsed high-energy neturon-induced spectral logging tool has been built and field-tested. The reaction of deuterium on tritium is used to generate pulses of 14-Mev neutrons. By detecting only the prompt gamma rays produced by neutron inelastic reactions in the formation, the presence and relative abundance of carbon, oxygen, calcium, silicon and other important elements may be ascertained from a gamma-ray spectrum. Gamma-ray spectra obtained in a shallow test well and in experimental field use show that it is possible to identify formations and their contained fluids.

Introduction
The penetrating gamma rays from naturally occurring radioactive elements in subsurface formations have been used for a number of years in well logging as a means of characterizing and distinguishing strata. Still another nuclear logging method which has been employed for some years consists of the bombardment of strata with neutrons and the measurement of the number of gamma rays produced by neutron capture reactions involving elements in subsurface strata. Since one of the principal elements entering into capture reactions is hydrogen, the latter procedure essentially results in a hydrogen log, whether the hydrogen be in combined form in either oil or water; thus, the log gives an indirect measure of porosity. These methods, with various refinements, have been developed to such an extent that they have become routine procedures in formation evaluation.
Neither gamma-ray logging nor conventional neutron logging, however, yields sufficient information to permits unequivocal identification of the mineralogic composition of formations, and neither method gives information which may be used for the positive identification of hydrocarbons in strata. Accordingly, a number of efforts have been made in recent years to gain additional information from nuclear logs. Brannon and Osoba have shown that it is possible to identify naturally occurring radioactive elements in subsurface formations by spectral analysis of gamma rays emanating from these elements. Such an identification is of value in the characterization of strata. A simplified form of spectral analysis of gamma radiation resulting from neutron capture reactions between elements in earth materials and bombarding neutrons has been used with some success under favorable conditions to differentiate between petroleum and water.
High-Speed Field Development Planning in the Presence of Uncertainty and Risk Through the use of Constrained Numerical Optimization and Analytical Simulation
Authors: Tilke Peter G. , Bogush Alexander , Bolanos Nelson , Corbett Chip , Kolupaev Aleksander , Grove Greg P. , Spath Jeff , Thambynayagam R. K. , Wu Jinyong , Zhou Wentao 
Published: June 2014

Abstract
We present a framework that automatically generates an optimal well placement plan (WPP) based on a reservoir model. The proposed WPP comprises wells, their completions, and the drilling schedule. A suite of high-speed computational components allows this WPP to be generated in minutes. Greenfields and brownfields are supported. Brownfields require consideration of historical and ongoing production by existing wells along with collision avoidance when proposing new wells. The proposed wells can be producers or water injectors with vertical, deviated, or horizontal geometries. Different development strategies can be investigated that allow targets to be driven by geology or standard pattern such as an inverted five-spot. In addition to proposing new wells, existing wells may be sidetracked or recompleted.
Optimization of the WPP uses a constrained downhill simplex approach. During a trial, WPPs proposed by the optimizer in earlier trials are extrapolated to propose a new WPP. The proposed WPP must satisfy a wide range of geometric, operational, contractual, and legal constraints on the surface and in the overburden and reservoir. Collision and hazard avoidance computation uses a geocomputation topology approach. When a feasible WPP is discovered, the production forecast is computed using a high-speed semi-analytical reservoir simulator, which renders a result within a few seconds, using an analytically computed pressure and explicitly computed saturation. This reservoir simulator is fully three-dimensional and discretizes the reservoir to represent the underlying heterogeneity. In addition to recovery, the framework allows a variety of objective functions including net present value, return on investment, and profitability index. Optimization in the presence of subsurface uncertainty is considered by using an ensemble of reservoir models. A proposed WPP will then have an uncertainty in the forecast value. For a specified aversion to risk, a conservative or aggressive WPP can then be optimized.
The framework has been applied to a variety of workflows. These include rapid evaluation of the potential of different waterflooding strategies, drilling multiple infill wells from existing platforms, and identification of sidetrack candidates in mature fields.
This new framework has many applications in the field development planning workflow, including rapid screening of multiple fields and development scenarios. The most promising scenarios can be used with detailed numerical simulation for further validation.
Field Implementation of a Relative Permeability Modifier during Stimulation Treatments: Case Histories and Lessons Learned After More than 3,000 Treatments
Authors: Vasquez Julio , Eoff Larry 
Published: June 2014

Abstract
Relative permeability modifiers (RPMs) have been used by the oil and gas industry for more than two decades to selectively help reduce excessive formation water production. RPM systems are appealing to operators because their deployment simplicity requires no zonal isolation (i.e., bullhead-type treatments). This paper discusses the application of a novel RPM system that was originally developed for water control; however, its application was extended to hydraulic fracturing, acid stimulation, overbalanced workover interventions, and waterflooding.
This RPM system is based on a hydrophobically modified water-soluble polymer that, once adsorbed to the surface of the rock, selectively reduces the effective permeability to any aqueous fluid with little or no damage to oil or gas production in both injection and production modes. The hydrophobic modification to the base polymer chain adds unique associative properties to the system that allow multiple novel applications. The following applications are discussed in this paper: (1) the combination of the RPMs with hydraulic fracturing stimulation treatments in intervals previously bypassed because of their proximity to mobile water zones; (2) the combination of RPMs with acid (matrix and non-matrix) stimulation treatments used as a diverting and water control agent; (3) RPMs during overbalanced workover interventions (i.e., wellbore cleanouts, tubing-conveyed perforating (TCP), and gravel packing) used as a fluid-loss control agent; and (4) RPMs during waterflooding for improved profile modification as a diverting agent. Because this RPM does not affect hydrocarbon permeability, this system does not require the use of breakers or a cleanup stage, eliminating possible negative impacts on post-stimulation well productivity.
To date, more than 3,000 treatments have been performed with this RPM system. This paper discusses the RPM performance testing and a wide variety of case histories detailing the applications described in different types of reservoirs and wellbore completions.
Reducing the uncertainty of static reservoir models: implementation of basin-scale geological constraints
Authors: Weltje Gert Jan , Dalman Rory , Karamitopoulos Pantelis , Sacchi Quinto 
Published: June 2014

Abstract
We propose a new workflow for building static reservoir models of siliciclastic fluvio-deltaic systems. The proposed strategy requires a process-based stratigraphic simulation model which incorporates a reservoir-scale alluvial architecture module nested within a low-resolution basin-scale (sequence-stratigraphic) model. The basin-scale model is run with the intent to approximate large-scale basin-fill properties (based on geological/geophysical background information about palaeotopography, sea level, sediment supply, subsidence, and so forth). Subsequently, the model may be stochastically optimised by dedicated post-processing software to mimic sub-grid (reservoir-scale) properties of selected parts of the basin fill. This approach allows us to narrow down the range of possible scenarios (realisations) from the outset, which results in more reliable uncertainty estimates associated with reservoir models. Pilot studies suggest that the improvement of geological credibility of stochastically simulated fluvial reservoir models may go hand-in-hand with a significant reduction of the computational effort of inverting basin-scale (process-based) stratigraphic forward models. The implementation of geological constraints on object-based models is expected to improve estimation of sand-body connectivity and dynamic reservoir behaviour, and will therefore contribute to reduction of the non-uniqueness in current static reservoir models. Furthermore, the uncertainty associated with each basin-scale parameter can be propagated all the way through to reserve estimation. The partitioning of the overall uncertainty into contributions at the basin and reservoir scales may be quantitatively assessed, and the information content of all available data may be quantified.
Opportunity of Enhanced Oil Recovery Low Salinity Water Injection: From Experimental Work to Simulation Study up to Field Proposal
Authors: Callegaro Chiara , Bartosek Martin , Masserano Franco , Nobili Marianna , Parracello Valerio Parasiliti , Pizzinelli Corrado Sebastiano , Caschili Alessandro 
Published: June 2014

Abstract
Low Salinity waterflooding is an emerging Enhanced Oil Recovery technique in which the salinity of the injected water is controlled to improve oil recovery vs. conventional, higher salinity waterflooding. The objective of this work is the evaluation of low salinity water injection as EOR process in an on-shore field in West Africa. The field is heavily faulted and highly heterogeneous. The reservoir fluid is light crude oil; very different productive behaviours are present in the field.
An experimental work was performed to verify the effectiveness of the process and make deeper investigation about the chemical and physical mechanisms involved in low salinity water injection. Core flooding experiments on reservoir porous media were carried out, giving promising results in terms of matrix additional oil recovery with low salinity waterflood.
Furthermore, a simulation work to predict the benefits in the field was executed. Core experiments were reproduced using a wettability change model to obtain low salinity water parameters, the salt-dependent relative permeability curves. The process was scaled up to a fine sector model, calibrated on historical production data, representing the area of interest for low salinity water pilot. Simulations of low salinity water injection were run in different forecast scenarios and additional recovery was compared with sea water injection.
In order to evaluate the global effect of low salinity water injection as EOR process, all the aspects were taken into consideration, decrease in residual oil saturation, permeability reduction, expected sweep efficiency on effective reservoir matrix volume. The experimental and simulation results were used for an economical feasibility study for a desalination plant in the field to reduce the salinity of current injected sea water.
Multi-Scale Simulation of WAG Flooding in Naturally Fractured Reservoirs
Authors: Elfeel Mohamed Ahmed , Al-Dhahli Adnan , Geiger Sebastian , van Dijke Marinus I. 
Published: June 2014

Abstract
Naturally Fractured Reservoirs (NFR) contain a significant amount of remaining petroleum reserves and are now being considered for water-alternating-gas (WAG) flooding as secondary or tertiary recovery. Reservoir simulation of WAG is very challenging even in non-fractured reservoirs because a proper set of saturation functions that describe the underlying physics is vitally important but associated with high uncertainty. For NFRs, another challenge is the upscaling of recovery processes, particularly the fracture-matrix transfer during three-phase flow, to the reservoir scale using dual-porosity or dual-permeability models.
In this work, we approach a solution to this challenge by building models at various scales, starting from pore-scale to an intermediate scale then to the reservoir scale. We show how pore-network modelling and fine grid modelling where the fractures and matrix are represented explicitly can be used to increase the accuracy of numerical simulations at the field-scale in order to predict recoveries for NFR during WAG. We study the sensitivity to WAG design parameters as well as the impact of matrix wettability on recovery. We also compare the fine grid model with an equivalent dual-porosity model.
Simulation at an intermediate scale showed at least 10% absolute change in recovery due to the choice of the empirical three-phase relative permeability model. In fine grid simulation with physically consistent pore-network derived three-phase relative permeability and capillary pressure, injected water and gas are predicted to displace each other, leaving oil behind, therefore reducing WAG efficiency. For this case, empirical models over-estimate recovery by 25%. Classical dual-porosity model over-estimates recovery during the early WAG cycles, and fails to adequately match recovery of the fine grid simulation.
Our multi-scale simulation approach identifies important factors and uncertainties when considering WAG flooding in NFR. It provides a methodology through which WAG recovery can be estimated using available technology while preserving the pore-scale physics for three-phase flow, which are crucial to making reliable forecasts at the reservoir scale.
Experimental Investigation of Polymer Flow through Water- and Oil-Wet Berea Sandstone Core Samples
Authors: Hatzignatiou D. G. , Moradi H. , Stavland Arne 
Published: June 2014

Abstract
Polymer behavior under different wettability conditions is investigated through coreflood experiments conducted on cores with different wettabilities, but of the same pore structure. Berea core samples are used in the experiments with the wettability of one core altered to oil-wet conditions. A series of polymer and water floodings are performed with the polymer properties in porous media calculated and the formation wettability evaluated based on the measured laboratory data.
The effect of wettability on polymer behavior in porous media is the main focus of this work. In the first part of this study, the bulk rheology of a hydrolyzed polyacrylamide (HPAM) dissolved in two synthetic brines of different salinities is studied. A Carreau-type model is fitted on the experimentally measured data and the effect of salinity on the rheological properties of the HPAM polymer is investigated. A power-law model is also developed for the same experimental data.
For the core flooding experiments, a new setup is implemented in which, instead of measuring manually the core effluent concentrations during the polymer flooding, a capillary tube is connected to the core outlet. Using the notion of the intrinsic viscosity, a formula is derived to estimate the polymer concentration from the pressure drop recorded across a capillary tube mounted at the core effluent. In addition, basic properties related to polymer flow in porous media, such as polymer adsorption, inaccessible pore volume, and apparent viscosity are evaluated for the cores and both wetting conditions.
From the bulk and coreflood experiments conducted in this work, several important findings are reported. The examined polymer solutions display both upper Newtonian and shear thinning flow regimes in our bulk rheology investigation, with the effect of brine salinity on polymer viscosities to be significant. From the core flooding experiments, both polymer shear thickening and degradation flow regimes are observed on the water-wet core sample. The oil recovery factors and oil recovery vs. time profiles for the Berea oil- and water-wet core samples vary significantly and in accordance to the expected wetting conditions of the cores. The Berea water-wet core has the highest value of polymer retention, inaccessible pore volume (IPV) and permeability reduction factor (RRF) compared to the oil-wet core sample. The results displayed in this work confirm that the formation wettability has a significant effect on the polymer behavior in porous media.
Dynamic Matrix-Fracture Transfer Behavior in Dual-Porosity Models
Authors: Su Shi , Gosselin Olivier , Parvizi Hadi , Giddins Marie Ann 
Published: June 2014

Abstract
A dual-porosity simulation model is a coarse upscaled representation of a naturally fractured reservoir. Fluid transfer between the matrix and the fracture is described by a matrix-fracture transfer function, which is dependent on a shape factor. However, the basic formulation assumes pseudosteady-state conditions and requires modifications to capture transient effects. This paper describes the use of a dynamic shape factor for matrix-fracture transmissibility with block-to-block effects to improve the simulation of oil recovery in a dual-porosity model.
A simple fine-grid single-porosity model is compared with a coarse-grid dual-porosity equivalent for a gas-oil system under gravity drainage without capillary effects. A time-varying relationship between the shape factor and the matrix oil saturation is derived by numerical analysis. Vertical block-to-block connections are included in the model to match oil reinfiltration from the fractures to the matrix. The saturation-dependent shape factor correlation is generalized for other matrix block sizes. An improved match to fine-grid recovery is achieved in the dual-porosity simulation through use of a dynamic transfer function and block-to-block effects. The methodology is shown to be appropriate for a range of matrix sizes and, with different relative permeability curves, for the matrix blocks. However, attention must be paid to the relationship between simulation grid cell size and geologic matrix block size. Additional study of block-to-block flows is recommended to further improve the predictive capability of the model.
Fast and accurate simulation of flow in naturally fractured reservoirs is often difficult to achieve. The standard matrix-fracture transfer model is unsuitable for many situations. In the example presented here, we show how a coarse simulation model can be used effectively to capture variations in dynamic matrix-fracture transfer behavior over time for a specific case. The approach can be generalized and applied to similar studies.
Extension and Verification of a Simple Model for Vertical Sweep in Foam Surfactant-Alternating-Gas Displacements
Authors: de Velde Harsenhorst R.M.. M. , Dharma A.S.. S. , Andrianov A.. , Rossen W.R.. R. 
Published: June 2014

Summary
Foam is a promising method to improve sweep in gas-injection enhanced-oil-recovery (EOR) projects. For cases in which well-to-well distances are large, the question arises whether foam can prevent gravity segregation over these distances. For such cases, theoretical studies suggest that the best process is to inject one large slug of surfactant followed by one large slug of gas. Shan and Rossen (2004) present a simple model for such a process that provides an initial assessment whether foam can prevent segregation over large distances. They did not extend their calculations to the large distances between wells in some potential applications, and they treated only the case in which vertical permeability kv equals horizontal permeability kh. Here, we extend the model to cases of kv &lt; kh. We derive an analytical solution for the limit as kv approaches zero, which could serve as a quick first estimate of feasibility for other cases. Surprisingly, the model predicts that gravity segregation is worse as kv decreases; the reason is that, with large kv, foam pushes downward in response to the pressure difference across the tilted foam front.
We illustrate the use of the model with an example from a North Sea field, in which the issue was whether foam could prevent gravity segregation over a distance of several kilometers. The simple model said this was feasible, and more-detailed 2D cross-section simulation then confirmed that segregation was insignificant over an interwell distance of 6 km.
One can fit the model parameters to foam parameters derived directly from laboratory data. We illustrate with a model fit by Rossen and Boeije (2013) to data of Persoff et al. (1991), a fit specifically designed for a hypothetical surfactant-alternating-gas (SAG) application. The fit of simulations to the simple model is closer than in the North Sea example, and the prediction that sweep is better with kv = kh than for kv = 0 is confirmed. Moreover, the idealized model predicts the injectivity in this case very accurately.
Smart Learning from Past Data Yields 50% Incremental Oil Production
Authors: Pairault S. , Daudin R. 
Published: June 2014

Abstract
This paper presents a novel methodology for re-developing mature fields and increasing their production and reserves. It has been successfully applied to Butte Voluntary Unit, Canada, where it yielded a 50% production increase. Such upside results from a rational and massive search for the best re-development plan. The method uses a reliable production forecast tool specifically developed and calibrated for the given field. This is based on a smart learning process from historical production data, constrained by reservoir and well physics. The tool is not only reliable, it is also very fast: any given production forecast can be played within seconds. A powerful search engine is used to generate, select, adjust, and compare 100,000s potential field development plans ("scenarios"). Those are ranked for best Net Present Value, within different sets of financial and technical constraints ("strategies").
The full process was successfully applied to Butte Voluntary Unit, a water flooded mature field in Western Canada. A comprehensive range of strategies was explored, enabling robust decisions with respect to future oil price assumption, and ranking investment priorities. After playing 600,000 different possible production scenarios, a financially optimized re-development plan was identified involving four conversions out of 69 candidates, and the drilling of four new infill wells out of 20 possible sweet spots, as well as an upgrade of the field injection capacity.
This re-development plan was actually implemented on the field and became operational during the summer of 2011. Since then, oil production has soared as planned and incremental 5 year-reserves about 50% above the baseline are being demonstrated. This project illustrates that historical production data of mature fields have plenty to tell, and demonstrates how they can be smartly used to engineer the right re-development path and unlock considerable upside with controlled investment and low risk.
Mature fields are gaining increasing importance within most oil & gas companies’ portfolios. Relying on several field proven successes, the technology presented in this paper is becoming a reference tool for re-developing mature fields.