bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach to Generating Fracture Conductivity
Authors: Gillard M. , Medvedev O. , Peña A. , Medvedev A. , Peñacorada F. , d'Huteau E. 
Published: February 2011

Abstract
The primary goal of a hydraulic fracturing treatment is to create a highly conductive flow path to the wellbore that economically increases well production. In moderate and high permeability wells the lack of adequate fracture conductivity is a limiting factor in the production potential of the well, whereas in tight gas reservoirs the limiting factor is often the effective fracture half-length. Even in the last case, adequate fracture conductivity is important to allow efficient recovery of the fracturing fluid.
Traditionally, efforts to enhance conductivity have been directed to improve the ability to flow through a porous proppant pack. The industry has extended significant efforts towards the goal of increasing proppant pack permeability through the development of less damaging carrier fluids, higher strength man-made proppants, more efficient fracturing fluid breakers and so on.
As an industry however, we continue to struggle with the fact that well testing frequently indicates disappointingly shorter or less conductive fractures than designed. Multiple studies indicate that proppant-pack retained permeability is often a small fraction of the maximum expected value.
This manuscript describes a novel hydraulic fracturing technique that enables a step-change approach towards increasing fracture conductivity. The technique is based on the creation of a network of open channels inside the fracture.
Modeling and experimental work indicates that the new technique can deliver conductivities in excess of ten-times those obtained from conventional fracture treatments. Extensive lab-, yard- and field- scale experiments combined with theoretical work allowed creating the framework that describes the physical processes occurring during the application of this new technique.
By providing significantly higher fracture conductivity, this new fracturing approach delivers a number of consequential benefits: better fracture cleanup; lower pressure loss within the fracture; longer effective fracture half-lengths, all of which will contribute to improved short- and long-term production.
A 15-well field study, selected from over fifty treatments performed up to date with this technique, is presented to show posttreatment results with significant gains in well production and expected ultimate recovery with respect to offset wells treated with conventional fracturing methods.
Permanent Tracers Embedded in Downhole Polymers Prove Their Monitoring Capabilities in a Hot Offshore Well
Authors: Nyhavn Fridtjof , Dyrli Anne D 
Published: February 2011

Abstract
Tracers are applied as embedded in polymers that are placed in the downhole completion. The Tracer Systems are designed to change behaviour as a function of the surrounding medium. Such behavior can be the release of tracer into one medium while keeping tight in another. Released tracers will migrate to surface where topside fluid samples are analyzed and the tracer concentrations in those are the basis for extracting Well Inflow Information.
The Tyrihans well, B-IAH T2, was cleaned-up in two sections and the 1100m long toe section was equipped with 3 unique oil soluble tracers that were placed along the production zone. The objective was to evaluate the quality of clean-up and (if necessary) also during a production restart 6 months later. The well had a downhole temperature of 137°C, higher than the operating temperatures for available Permanent Tracer Systems. So a new Tracer System had to be developed and qualified for the case.
RESMAN's tracer systems indicate that the toe is contributing as expected to the fluid production and that additional production occurs along the well bore. All completion fluids in the lower completion seem to be fully cleaned-up. All 3 tracers adds value to the interpretation. Extra information on the fluid dynamics of the clean-up process could be indicated.
Novel Emulsified Acid Boosts Production in a Major Carbonate Oil Field with Asphaltene Problems
Authors: Appicciutoli Danilo , Maier Robert , Strippoli Danilo Pasquale , Tiani Alessandro , Mauri Luca 
Published: February 2011

Abstract
When performing matrix-acid treatments, the goal is to stimulate the formation as deeply as possible, distributing the acid uniformly over the total zone of interest. Uniform distribution is even more important when intervals are long, horizontal, or several zones with natural fractures predominantly take the reactive fluid. In Italy's major oil-producing field, all of these challenges are faced.
In addition, during production, asphaltenes form and are deposited in the well, making it even more difficult to distribute the acid evenly. Because the field is located in an environmentally sensitive area, all fluids need to be mixed and pumped using a zero-operational-risk philosophy. Some of the matrix-stimulation challenges were overcome as a result of the development of a novel emulsified acid that combines the practiced asphaltene-dissolving technique with proven acid-diversion technology. The environmental challenges are overcome by creating an oil-external/acid-internal emulsion, on-the-fly, just before the fluid is pumped downhole.
This paper describes the engineered process of finding solutions to the challenges, beginning with laboratory testing to develop and optimize the solvent part of the innovative acid system. Further, an overview of how operational difficulties were resolved and how the innovative fluid system was applied is presented. The first section of the paper outlines laboratory testing, showing that an emulsified-acid system can be mixed with custom-tailored asphaltene-solving blends and provide the desired benefits for matrix acidizing, such as a slower acid reaction, higher base viscosity, and excellent emulsion stability in temperature. The second part of the paper explains the equipment setup used to create the acid system ready for field application in an environmentally sensitive area. The third part of the paper describes how the novel acidizing approach in its first field application boosted production to unexpected highs.
Using a Fully-Coupled Flow and Geomechanical Simulator To Model Injection Into Heavy-Oil Reservoirs
Authors: Huang Hao , Wattenbarger R. Chick , Gai Xiuli , Brown William P. , Hehmeyer Owen J. , Wang Jianlin , Long Ted A. 
Published: February 2011

Abstract
In this paper, the geomechanical factors that may affect injection processes in heavy oil recovery are investigated. To accurately capture the geomechanical effects, a new numerical formulation that allows fully coupled simulation of porous media flow and geomechanical deformation is proposed. Two salient features of this new coupling formulation are (1) all flow and geomechanical equations are solved implicitly in one single matrix equation, and (2) it allows reuse of matrices from both a traditional fully implicit multi-component reservoir simulator and a nonlinear geomechanics simulator. The former feature ensures stable coupling between the reservoir flow and geomechanics, and the latter significantly reduces the programming work. Numerical examples are given to demonstrate the accuracy and convergence performance of the new formulation.
The proposed formulation is then employed to model injection into heavy oil reservoirs. The numerical investigation revealed that geomechanical factors, such as in-situ stress anisotropy and the incompatible deformation of reservoir rock and attached impermeable rock, can result in uneven shear dilation, and hence alter the sweep of the injected fluid. Coupled geomechanics simulation also gives rather different transient pressure response from that of uncoupled simulation. In the end, an example on how to utilize the formation deformation results to evaluate casing and cap rock integrities is given.
Modeling High-Viscosity Oil/Water Flows in Horizontal and Vertical Pipes
Authors: Zhang H.-Q. , Vuong D. H. , Sarica C. 
Published: February 2011

Abstract
Water is produced along with heavy oil either during the primary production or enhanced oil recovery. Therefore, oil-water flow is a common occurrence in heavy oil production and transportation. Production system design is strongly dependent on the accurate predictions of the oil-water flow behavior. The predictions of previous mechanistic models for pressure gradient and water holdup are tested with the data acquired, and significant discrepancies are identified, especially for horizontal flow (Vuong 2009). The model performance is largely dependent on the predictions of phase inversion, distribution and interaction. Based on the new understandings from experimental observations, The Zhang and Sarica (2006) unified model is modified by adding a new closure relationship for water wetted wall fraction in stratified flow and a new interfacial shear model based on mixing length theory. The new model is compared with both high viscosity and low viscosity oil-water flow experimental results, and significant improvements are observed.
The Impact of Hierarchical Fracture Networks on Flow Partitioning in Carbonate Reservoirs: Examples Based on a Jurassic Carbonate Ramp Analog from the High Atlas, Morocco
Authors: Agar Susan M. , Geiger Sebastian , Matthäi Stephan , Alway Robert , Tomas Sara , Immenhauser Adrian , Shekhar Ravi , Paul Jonathan , Benson Greg , Karcz Zvi , Kabiri Lahcen 
Published: February 2011

Abstract
Hydrocarbon reservoirs commonly contain an array of fine-scale structures that are below the resolution of seismic images. These features may impact flow behavior and recovery, but their specific impacts may be obscured by the upscaling process for sector and field-scale reservoir simulations. It is therefore important to identify those situations in which subseismic structures can introduce significant departures from full-field flow predictions. Using exposures of Jurassic carbonate outcrops near the village of Amellago in the High Atlas Mountains of Morocco, we have developed a series of flow simulations to explore the interactions of a hierarchical fracture network with the rock matrix of carbonate ramp strata. Model geometries were constructed in CAD software using field interpretations and LiDAR1 data of an outcrop area that is 350 m long by 100 m high. The impact of water injection on oil recovery between an injector and producer pair was investigated. Simulations were performed by a single medium reservoir simulator using a single mesh to represent fracture planes as well as rock-matrix volumes. The effects of changing scenarios for rock permeability and porosity as well as facture permeability distributions were investigated. First-order results show that the best recovery was achieved by a model with a high permeability, homogeneous matrix combined with a heterogeneous fracture network. The worst recovery scenario was given by a model with low, homogeneous permeability and high fracture permeabilities. After approximately 450 days there is a divergence in recovery profiles. Three models continue to recover oil while average oil saturations for the other 4 models start to plateau. The divergence does not simply reflect homogeneous vs. heterogeneous matrix models but captures a threshold between high and medium fracture-permeability scenarios that determines whether recovery continues in late time or the well starts to water out. The results highlight the importance of the permeability contrasts between the matrix and the fractures for overall recovery and the very significant impact that fractures can have on recovery by creating shadow zones and providing critical connections between permeable layers. The presence of the hierarchical fracture network developed strong fingering even in homogeneous matrix cases and evolving velocity patterns reveal competing fluid pathways among matrix and fracture routes. Insights from these models can help to develop production strategies to improve recovery from fractured carbonate reservoirs and provide an initial platform from which to extend further evaluations of different populations of conductive and baffling structures, spatial variations in wettability and capillary pressures and well positions.
Paraffin-Plug Remediation in Deep Water Wells via Capillary Tubing: A Cost Effective Alternative
Authors: Embrey Mark , Larke James 
Published: February 2011

Abstract
Description: A 5/8" capillary unit was used to effectively remediate a paraffin plug from a deep water Gulf of Mexico well saving the operator the expense of a coiled tubing job.
Application: The formation of organic deposition in oil wells is inevitable. This hindrance is an even larger problem in deep water wells where the produced fluid experiences temperatures near freezing at the mud line. Paraffin inhibition methods such as down hole injection of chemicals and insulated risers can be effective as long as the well is flowing. If the well is shut in for a long period of time, these inhibition methods are not effective and a paraffin plug is likely.
Results, Observations, Conclusion: A capillary tubing unit was used to deploy 5/8" capillary tubing to the paraffin plug. A paraffin solvent was then pumped down the capillary tubing to remove the plug. After adequate soak time the blockage was cleared, and the operator gained communication with the well.
Pumping solvents from surface or down hole through the chemical injection mandrels was proven ineffective due to the solvent not being able to contact the plug. Washing or milling the plug with a coiled tubing unit or workover rig was not desired due to the cost and exposure. Other advantages of utilizing the capillary unit were: small footprint, less personnel required, reduced safety risk, less rig up and rig down time, and the crane was freed up by not having to support the injector head.
Significance of Subject Matter: Operators now have a cost effective alternative for removing small amounts of deposition in a well. The light weight, small footprint capillary units can access platforms with de-rated cranes and limited work decks giving operators other options for intervention work.
Horizontal Drilling and Well Completion Optimization in a North Dakota Bakken Oilfield
Authors: Zander Dennis , Czehura Michael , Snyder Daniel J , Seale Rocky 
Published: February 2011

Abstract
First discovered in 1951, development of the Bakken formation in the Williston Basin has been problematic and inconsistent. However, technological advancements in horizontal drilling and completions in the past decade have steadily improved production results and consistency on a well by well basis. So much so, that the United States Geologic Survey (USGS) reported in 2008 that the undiscovered, technically recoverable oil in the Bakken was between 3 to 4.3 billion barrels.
How many fracture stages to run and how far apart to space stages in horizontal wells are prevalent questions asked by the oil and gas industry. This study provides insight into the advantages of various stage numbers and optimum stage spacing by analyzing up to 15 months of production results from horizontal wells targeting the Bakken in the Stanley Field, North Dakota. These wells were completed with open hole, multi-stage fracturing systems (OHMS) and production is compared to offset wells and field averages.
Advancements in OHMS completion and fracturing technology have enabled maximized production from this asset. The lessons learned and methodology can be utilized for other unconventional oil and gas plays around the world.
Meeting the Challenges in the Downhole Scale Control for High-Water-Production Horizontal Wells in Environmentally Sensitive Part of the Norwegian North Sea
Authors: Chen P. , Montgomerie H. , Hagen T. , Vikane O. , Juliussen B. , Haaland T. , Nguyen K. , Chen T. 
Published: February 2011

Abstract
Due to the seawater injections in one of in Norwegian Sea oil fields, sulfate scale depositions have been identified in the near well bore region and inside the production well. The scale inhibitor squeeze treatments are regularly carried out. Most of the production wells are horizontal producing with a fairly high water cut and increasing the squeeze treatment life is one of the major issues for the selection of scale inhibitors and placement technologies. In addition, the inhibitor selected has to be environmentally acceptable and meet the regulations from the environmental authorities. Both challenges from the high water production wells and environmental requirements limited the choice of the inhibitor candidate selections.
Through extensive laboratory qualification testing, a newly developed polymer inhibitor was qualified for the field and satisfactory results were achieved from several field trials. This paper presents the inhibitor chemistry as well as the laboratory tests such as inhibitor efficiency, compatibility and inhibitor core flood. The environmental properties of the chemistry will be outlined. A comparison was made between the field treatments using this polymer inhibitor and widely applied polymer chemistries. The treatment optimization using a software package will also be highlighted. The field has utilized the gelled scale inhibitor package and the technology improved the inhibitor placement in the horizontal well. The updated treatment data will be reviewed in this paper.
A two-stage well placement optimization method based on adjoint gradient
Authors: Forouzanfar Fahim , Li Gaoming , Reynolds A. C. 
Published: February 2011

Abstract
As well locations are represented as integer well gridblock indices in reservoir simulators, determining optimal well locations is most naturally treated as a discrete optimization problem. A few recent papers in the literature have attempted to convert this discrete optimization problem into a continuous optimization problem, but most of these papers require that one specify a priori both the number of wells to be drilled and the operating rates (or bottomhole pressures) for the specified operational life of the reservoir. Therefore, the final optimal well locations may not be optimal when different well rates (or bottomhole pressure) and/or reservoir production life are specified. The methodology in this paper attempts to mitigate the effects of an ad hoc specification of both operating well rates (or pressures) and operational reservoir life by using an initialization step to determine an appropriate total reservoir water injection rate and/or total reservoir production rate for the specified operational life. After the initialization stage a second stage is performed in which we estimate (i) the optimal number of water injection wells and/or producing wells; (ii) the optimal location of these wells and (iii) the optimal rates at these wells. Both stages use a gradient based optimization algorithm with the relevant gradient computed by a combination of the adjoint method and analytical methods for linear constraints which are imposed using a gradient projection method. A practical method is proposed for imposing nonlinear bound constraints on the bottomhole pressure of each well.
Does the Presence of Natural Fractures Have an Impact on Production? A Case Study From the Middle Bakken Dolomite, North Dakota
Authors: Mullen M. , Pitcher J. , Hinz D. , Everts M. , Dunbar D. , Carlstrom G. , Brenize G. 
Published: February 2011

Abstract
During the last 10 years, more than 2,000 horizontal wells have been drilled and completed in the Middle Bakken formation, which is sandwiched between the two Bakken organic-rich shales. Although most of the debate about this reservoir has centered on the lateral length, stimulation treatment, and the number of treatments, little work has been performed to explore the variations of rock properties and the effect of natural fractures along the 6,000 to 10,000 ft lateral lengths.
Maintaining the horizontal well between the two Bakken shales is easily accomplished with only a gamma ray tool. There are, however, two important questions to be addressed. First, is this an optimal practice for well placement? Second, is there a "sweet spot" layer in which the horizontal well should be placed to increase production?
In a recent well, an azimuthally-focused resistivity (AFR) tool and an azimuthal deep-reading resistivity (ADR) tool were run as a final wiper trip to investigate the location of natural fracture swarms and the variations of rock properties along the 10,000-ft lateral. The goal of this exercise was to test the concept of improving production by using a "smart" horizontal completion technique, spacing the swellable packers, and locating fracture stages based on horizontal reservoir data. The AFR image log identified more than 839 individual fractures in four fracture swarms. The ADR mapping showed approximately 40% of the lateral in the sweet spot layer. The evaluation of a post-stimulation oil tracer indicates that these sweet spot layers provide 70% of the production after stimulation. If the well had been geosteered to remain within the sweet spot using a smart completion technology, the production modeling suggests that production could have been increased by 20%.
Enhanced Production Profiling of Gas Wells Using a New Method to Model the Geothermal Temperature Gradient
Authors: Johnson M. D. , Briceño M. G. , Hutchings A. C. , George D. R. 
Published: February 2011

Abstract
Quantitative gas and water production profiling is very useful in completion and production performance evaluation. Production profile analysis that incorporates mass rate modeling of the flowing temperature has dramatically increased confidence in profiling results. Accurate mass rate modeling requires an accurate estimate of the geothermal temperature gradient. The conventional technique of estimating a linear geothermal gradient is not reasonable in producing regions with long completion intervals and complex lithologies. This paper will detail a new method of simulating the geothermal temperature gradient and advances in quantitative production profiling.
A multi-well study was conducted in the Piceance Basin in Northwestern Colorado because of the unique effect of lithology on the geothermal gradient. Coal, sand and shale sequences which impact the geothermal gradient must be taken into consideration. The study includes open and cased hole log data to define lithology and shut-in temperature data to characterize the geothermal gradient. An analytical simulator was developed to model the geothermal gradient. Research in rock, mineral and fluid thermal conductivities is utilized to qualify the field data and analytical model.
Results demonstrate that higher shale volume and coal beds increase the geothermal gradient above clean sand layer gradients. Measured geothermal gradients across coal bearing intervals are an order of magnitude higher than clean sand intervals. Geothermal gradients from the simulator were used as constraints in production profile analyses. The analyses will illustrate the identification and quantification of zonal gas and water production, even when some of the wells were flowing under adverse conditions of low gas rate, severe slug flow and high water production.
Enhanced production profiling has enabled the operator to enhance their reservoir characterization, completion strategies and production performance of future offset wells. Other applications for the technology include: 1) production profiling in similar regions with complex lithology and non-linear geothermal gradient, and 2) distributed temperature sensing used for continuous temperature and production profile monitoring.