bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Triangle "U" Sussex Unit - A Chemical Flood Case History
Authors: Smith J.E. , Larsen Dan 
Published: December 2007

Abstract
The Triangle "U" Unit is located in Campbell County, Wyoming, in the Powder River Basin. The field produces mainly from the Sussex "A" Sandstone, with completions and limited production from the Sussex "B". The flood recovered 12.8% OOIP on primary prior to the waterflood, which commenced in March, 1981. The Sussex "A" is relatively tight, with an average permeability of 15 md and porosity of 13.5%. The rock contains swelling and migrating clays and the initial injection water source was fresh, leading to concerns about long-term injectivity.
To stabilize clays, two different processes were applied. Earlier injection wells were treated with a combination of potassium chloride and cationic polymer. Later injection wells were treated with potassium hydroxide (KOH). A recent comparison of long- term performance of the two groups of injection wells shows that the wells treated with KOH injected 556,000 BBLS/porosity-foot more water than the wells treated with cationic polymer, in 1.4 years less time. Following KOH, all injection wells were put on a low concentration of imbibition agent to maximize in-depth penetration of water into low permeable rock. Cumulative oil recovery through March, 1997, is 36.4% OOlP, compared to the original waterflood projection of 26.6% OOlP. A total of 37.7% PV water has been injected, and the water-oil-ratio is currently 0.71, for a fairly efficient flood in this tight, dirty sandstone.
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A Case History: Completion and Stimulation of Horizontal Wells with Multiple Transverse Hydraulic Fractures in the Lost Hills Diatomite
Authors: Emanuele M.A. , Minner W.A. , Weijers L. , Broussard E.J. , Blevens D.M. , Taylor B.T. 
Published: December 2007

Abstract
The Lost Hills Field Diatomite has traditionally been developed using vertical wells completed with multiple propped hydraulic fracture treatment stages. As the main portion of the field is nearing full development at 2 1/2-acres per producer, the search for additional reserves has moved out to the flanks of the field's anticlinal structure. Due to limited pay thickness, these flank portions of the field will not support economic vertical well development. The use of horizontal wells was determined to have the best chance to economically develop these areas of the field. To evaluate this development concept, three horizontal wells were drilled and completed over the time period from November 1996 to December 1997
To assist with the horizontal well design and evaluation, several vertical data wells were drilled offset and parallel to the intended well path of each horizontal well. Additionally, two vertical core wells were drilled in line with the toe and heel of the horizontal well paths. These data wells were utilized to estimate properties such as in-situ stress profiles, pore pressure gradients, rock properties and fluid saturations, and to determine horizontal well vertical depth placement. The horizontal wells were then drilled in the direction of minimum horizontal stress (transverse to the preferred hydraulic fracture orientation) and completed with multiple-staged propped hydraulic fracture treatments.
During the completion of the three horizontal wells, hydraulic fracture growth behavior was characterized using surface tiltmeter fracture mapping and real-time fracture pressure analysis. In the third horizontal well, downhole tiltmeter fracture mapping was also used. This combination of fracture diagnostics provided significant insights into hydraulic fracture behavior, allowing diagnosis of anomalous fracture growth behavior and evaluation of remediation measures. Fracture diagnostics during the first horizontal well revealed an unexpectedly complex near-wellbore fracture geometry, a result of fracture initiation problems. These problems slowed the completion process and severely harmed the effectiveness of the fracture-to-wellbore connection. In the subsequent horizontal wells, a number of design and execution changes were made which resulted in simpler near-wellbore fracture geometry and a greatly improved production response.
The paper provides an overview of the completion and stimulation of all three horizontal wells, describes the lessons learned along the way, and discusses the implications for future Lost Hills horizontal well development.
P. 335
Horizontal Drilling Success in the East Painter Field of Southwest Wyoming
Authors: Weatherl M.H. 
Published: December 2007

Abstract
Horizontal technology was first utilized in the East Painter Field during the summer of 1996 through the drilling of the EPRU 41 - 1 8AH well. This was the first application of horizontal technology in the Nugget formation in the Rocky Mountains in recent years. The only other effort occurred in 1988 and has been previously described (1). Substantial success was achieved and several breakthroughs occurred with regard to drilling and completion philosophy for this type of well. This paper describes the background, planning, drilling, and completion sequence for EPRU 41-1 8AH. A review of more recent horizontal drilling efforts in the Field is provided as well.
P. 349
Induced Stress Diversion: A Novel Approach to Fracturing Multiple Pay Sands of the NBU Field, Uintah Co., Utah
Authors: Hewett T.W. , Spence C.J. 
Published: December 2007

Abstract
This paper presents results of utilizing "Induced Stress Diversion" (ISD) to fracture stimulate multiple pay sands in the Natural Buttes Field of Uintah County, Utah. Historically, these multiple pay sands have been stimulated with the Limited Entry technique. To a lesser degree, some wells have been stimulated in stages using positive isolation. The decision to try "Induced Stress Diversion" (ISD) was made to combine the economies of the limited entry technique with the superior production results expected of a staged completion. The technique involves pumping multiple flacs in a well relying on the Induced Stress imparted by the first fracture stimulation to divert the subsequent frac into the desired zone (i.e. no positive isolation).
The ISD technique has worked well in many instances to date. This is especially notable because the majority of wells thus far have been done without consistent attempts to close the fracture prior to commencing the next fracture stage. To allow the technique to have wider application, emphasis is currently directed at improved methods of inducing screenout. Based on initial results, the technique appears to have wide application and could improve the economics of developing multiple-pay reservoirs.
P. 375
Hydraulic Fracturing of the Frontier Zone in West-Central Wyoming A Case History
Authors: Lehman L.V. , Yaritz J.G. , Natvig R. 
Published: December 2007

Abstract
This case-history paper shows that dry-gas sandstone reservoirs in the Frontier zone in west-central Wyoming produce more gas when they are fracture-stimulated with fracturing fluids at lower pH values than conventional high-pH fracturing fluids with pH values greater than 10. Fracturing fluids at reduced pH values may be broken with oxidizing or enzyme breakers that are either encapsulated or applied in the conventional manner. Databases analyzed for this paper show that dry-gas sandstone wells stimulated with conventional high-pH borate (CHPHB) fluids produce less hydrocarbon during a comparable time frame than similar wells stimulated with zirconium-crosslinked fluids at moderate pH levels.
The merits of low-guar borate (LGB) at lowered pH values have been documented previously. This paper will introduce and discuss the benefits of using a low-polymer zirconium fracturing fluid at neutral pH values in dry-gas sandstone applications. Information and discussion are presented as follows:Retained-conductivity tests were performed using dry-gas flowback. These test practices fit results for dry-gas sandstones better than conventional conductivity testing using water as the flowback medium.The properties that make CHPHB popular in many applications may not be the optimum method to stimulate low- permeability, dry-gas sandstones. CHPHB fluids are borate gels complexed at high-pH values &gt;10).The geochemistry of some formations may not be suitable to fracture with high-pH fluids.LPZ, a low-polymer zirconium fracturing fluid is introduced as an alternative stimulation fluid. LPZ shows better performance than CHPHB for dry-gas sandstone reservoirs.
P. 495
High-Rate Foam Fracturing
Authors: Harris Phillip C. , Pippin Mike 
Published: December 2007

Abstract
Foam-fracturing treatments pumped down 3.- 5-to 4.5-in. tubing at up to 80 bbl/min have presented problems in control and execution. Wellhead pressures used to predict net entry pressure can give erratic results in the absence of good knowledge of bottomhole pressure (BHP). Since nitrogen (N2) delivery rates are pressure sensitive, errors in BHP estimation cause control problems with both rate and foam quality. Perforation erosion, if unaccounted for, can signal a need for increase in rate to maintain BHP.
We used a laboratory study of foam in laminar and turbulent flow and a series of field experiments with bottomhole gauges to calibrate foam friction-pressure in tubulars at very high rates. To measure the viscosity of foam fluid with N at 1,000 psi, we used a small-scale, flow-loop viscometer that could be applied in both laminar and turbulent flow. Foam parameters included foam qualities from 25 to 80% N2 and guar concentrations from 0 to 40 lb/Mgal. The effects of surfactant concentrations from 0.2 to 1.0% were also studied.
Field foam treatments pumped at high foam rates were equipped with bottomhole real-time transmitting gauges. Step-rate tests were performed on both neat foam and sand-laden foam to calculate friction pressures. Actual friction pressures from these treatments were compared with pressures based on laboratory data. The laboratory correlation can predict tubular friction accurately for foam fluids up to very high foam rates.
In several of the treatments, small perforations were used in an attempt to provide limited entry stimulation. With the bottomhole-gauge data, we were able to assess the effects of perforation erosion because of changes in sand concentration.
Results of this study were used to support the design of lower foam frac rates. The average rate of 80 bbl/min was lowered to 40 bbl/min resulting in a fracturing cost savings of approximately ﹩7,400 per treatment. The success of these lower rates has been verified by both after-frac tracer logs and on-line production.
P. 509
Porosity and Permeability Prediction in Low-Permeability Gas Reservoirs From Well Logs Using Neura Networks
Authors: Olson Terrilyn M. 
Published: December 2007

Abstract
Artificial neural networks are gaining popularity as tools for estimating reservoir parameters from limited, common data suites. Requirements for their use include input data such as well logs that relate to the desired output, and "truth" data for training. Two case studies will be used to illustrate the use of neural networks to predict porosity and permeability from log data. In both cases, the predictions were needed for field studies aimed at improving reservoir management and optimizing production.
In the giant Hugoton gas field in Kansas, porosity was predicted from spectral gamma ray, photoelectric, and bulk density data with generic neural network software. Such software allowed the relationship developed by the neural network to be translated into an equation that could be readily applied to all wells with the requisite log curves. Permeability was predicted using a more log-oriented type of software, one that incorporated depth windows of input data in generating and applying the network. In addition to the input curves used for porosity, neutron logs were used in the permeability prediction. In the Hugoton example, mineralogy was a critical factor in porosity and permeability determination, so most of the input data provided information about mineral constituents of the reservoir. Core analyses served as "truth" cases in training both porosity and permeability neural networks.
In the Red Oak gas field in Oklahoma, where density logs are commonly absent or of poor quality, multiple neural networks were developed to predict density from gamma ray and deep induction data. A combination of measured and predicted density curves were then used to calculate porosity.
One additional network was built to estimate permeability from gamma ray, induction, and density data over 5 orders of magnitude of permeability, with core plug permeability measurements used as truth in training. Key features of these networks were selective rather than statistical training, back prediction of input data for validation, and the use of vertical intervals of input data.
One additional network was built to estimate permeability form gamma ray, induction, and density data over 5 orders of magnitude of permeability, with core plug permeability measurements used as truth in training. Key features of these networks were selective rather that statistical training, back prediction of input data for validation, and the use of vertical intervals of input data.
P. 563
Well Head Test Analysis: Save and Safe
Authors: Dall&apos;Olio D. , Vignati L. 
Published: December 2007

Abstract
A methodology was developed which allows the use of well head pressure record for test interpretation purpose, correcting the obtained results to reservoir conditions. The methodology was validated on Italian gas fields comparing the results of the bottom-hole and well-head data analyses for depth ranging between 1000 and 4000 meters and gas rate between 50 to 1000 kSm3/d. Problems could arise when a massive two-phase flow in tubing occurs, because the well bore effects can reduce the quality of interpretation.
P. 139
Analysis of Linear Flow in Gas Well Production
Authors: El-Banbi Ahmed H. , Wattenbarger Robert A. 
Published: December 2007

Abstract
Linear flow may be a very important flow regime in fractured gas wells. It is also important in some unfractured wells. This paper presents practical approach to analyze both pressure (well testing) and production rate (decline curve analysis) data which is influenced by linear flow. The paper explains two approaches to analyze the date (hand calculations and curve fitting). It uses analytical solutions that are adapted to different reservoir models. These models include fractured wells and wells producing reservoirs with high permeability streaks. Permeability, flow area, and pore volume may be obtained from either pressure or production rate data. The constant rate solutions are different form the constant pressure solutions. The use of the wrong equations in the analysis may result in errors as high as 60%. The paper also shows the application of these techniques in analyzing field data.
P. 145
Drainage Efficiency in Naturally Fractured Tight Gas Sandstone Reservoirs
Authors: Harstad H. , Teufel L.W. , Lorenz J.C. 
Published: December 2007

Abstract
Modeling of the Mesaverde Formation in the San Juan Basin, northwestern New Mexico, shows the importance of using realistic drainage patterns in a naturally fractured reservoir. Fractures not only enhance the overall porosity and permeability of these reservoirs, but fractures also create significant permeability an isotropy. Permeability an isotropy causes the drainage area around the wells to be elliptical. Directional permeability is best found with multiple well interference tests. Predicted potential for infill drilling depends on the modeling approach, because elliptical drainage creates more overlap and undrained sections than a more radial drainage in an isotropic permeability case. Modeling with permeability anisotropy increases the potential for infill drilling and identifies optimum locations for new infill wells.
This approach has been applied in the Mesaverde Formation to determine economic optimization of infill drilling in these reservoirs and demonstrates that field development based on elliptical drainage areas can lead to a reduction in drainage overlap of adjacent wells and prevent leaving undrained areas. From multiple well interference testing a strong permeability an isotropy was found. Reservoir simulations were performed in pilot areas of different fracture intensity to quantify the potential for infill drilling, reducing the well spacing from 320 to 160 acre. Simulation results indicate areas of effective drainage, the optimum locations for infill wells, and the additional recovery from infill wells.
P. 157
Non-Darcy Measurements in Dry Core and the Effect of Immobile Liquid
Authors: Coles M.E. , Hartman K.J. 
Published: December 2007

Abstract
Non-Darcy flow increases the pressure drop required to establish a desired gas well production rate, thus decreasing productivity. This increased pressure drop is exacerbated by the liquid drop-out and build-up which occurs in gas condensate wells. The additional pressure drop caused by the two phase non-Darcy flow can have a dramatic effect on the flowing bottom hole pressure required to maintain producing rates, especially in high rate gas condensate systems. Neglecting or underestimating this effect will cause optimistic predictions of the maintenance of gas rate plateau.
Literature values for measured inertial coefficients, (which quantify non-Darcy flow pressure drops) show a scatter of a one to two orders magnitude for a given permeability. Measurements of inertial coefficients (betas) may or may not agree with literature reported values. Use of literature reported permeability - beta relationships to calculate beta may not be appropriate and may lead to significant errors. These errors increase with increasing flow rate and decreasing permeability.
This paper presents transient flow beta measurements obtained in dry core samples and in samples containing different saturations of immobile liquid. Results from core samples from three different reservoirs and one outcrop are included. A method has been developed to estimate the effective beta at different liquid saturations using core samples containing various saturations of solidified paraffin wax that mimic an immobile condensate phase. Continued validation of this technique will allow simplified and inexpensive beta measurements as functions of saturation and permeability
A relationship has been derived which allows the inertial coefficient to be estimated as a function of effective permeability and effective porosity. This relationship appears to hold for almost all of the core samples tested and includes both dry and saturated samples. The relationship, which includes both permeability and porosity, provides significantly reduced scatter compared with previous permeability-beta relationships and allows better understanding and estimation of beta.
P. 193
Preliminary Investigation of Coalbed Methane Potential of the Zonguldak Basin in Turkey
Authors: Serpen Umran , Alpkaya Ebru N. , Ozkan Erdal 
Published: December 2007

Abstract
This paper presents the results of a preliminary investigation of the coalbed methane potential of the Zonguldak Basin in Turkey. A stochastic approach is used in the investigation primarily because of the lack of sufficient data. The results clearly indicate the adequacy and the advantage of the stochastic approach over the deterministic procedures. The Monte Carlo simulation is used to obtain the probability distribution of in-situ and recoverable coalbed methane reserves in the Zonguldak Basin. An economic evaluation of a potential development project is also presented. It is shown that despite the conservative estimates of the reserves, coal bed methane production from the Zonguldak Basin is a feasible project.
P. 227
Minimizing Multiple Fractures in Coalbed Methane Fracturing Operations
Authors: Kilstrom Kevin , van Gijtenbeek Klaas , Tjoonk Richard , Palmer Ian 
Published: December 2007

Abstract
This case history paper describes a technique that minimizes the creation of multiple fractures in deep coal seams during hydraulic fracturing operations. The technique enabled the operator and the service company to perform 24 nitrogen foam-fluid fracturing treatments in 33 days in the Upper Silesian basin (Poland).
The creation of multiple fractures is a phenomenon often encountered during fracturing operations in coal seams and is the most probable cause of early screenouts. During this fracturing campaign, early screenouts were observed at sand concentrations less than 3 lb/gal. These screenouts were attributed to a lack of fracture width caused by the presence of multiple fractures, including possible horizontal fracture components or tortuosity.
The operator and the service company developed a technique that involves pumping a small volume of highly viscous crosslinked gel before the main fracturing treatment. This technique prevented early screenouts and allowed the higher sand concentrations to be pumped.
P. 237
The Effect of Shales on Mixing in Underground Gas Storage
Authors: Verlaan M.L. , Barzandji O.H.M. , Dronkert H. , van Kruijsdijk C.P.J.W. 
Published: December 2007

Abstract
This paper focuses on an important problem of gas storage projects; the mixing of the cushion gas and the storage gas. Due to mixing, the reproduced gas may not meet customer specifications or valuable gas becomes unrecoverable. In this work we address the effect of shales on the mixing process.
The shales in the gas storage site belong to the 200 m thick Rotliegend sandstone and occur at the base of aeolian facies sequences or are associated with fluviatile intervals between the aeolian dune facies. The horizontal continuity of the shale is strongly facies dependent.
The objective of this paper is to investigate field scale dispersion during cyclic injection and production. Based on shale size distribution we calculate the transfer of gas through shale breaks. This results in an effective dispersion depending on permeability contrast, injected volume and number of cycles.
We observed that shales smaller than the characteristic displacement length contribute to the effective dispersion, while the larger shales do not affect the mixing.
For narrow shale size distributions, the effective mixing is very sensitive to small changes in injection or production volume.
We conclude that shales play an important role in field scale dispersion, and could account for the high dispersivities measured in field tests.
P. 487
An Improved Model for Collapse Pressure of Oval Coiled Tubing
Authors: Zheng Andrew S. 
Published: December 2007

Abstract
This paper presents a new modeling technique to predict collapse pressure of oval coiled tubing. Through finite element analysis, a failure mechanism for tubing collapse is identified and a collapse model proposed. This model relates the tubing collapse pressure with its yield strength, ovality and its D/t ratio. Collapse pressures predicted by this model correlates well with FEM prediction. Collapse experiments were also performed to generate test data for collapse pressure under various ovality. To better simulate the actual material behavior in a typical tubing operation, the ovality in the collapse experiments was generated through a fatigue machine. Predictions from this model are compared against the experimental data as well as other published test data and good agreement is achieved. This new model predicts very well the effect of the ovality and axial force on the collapse pressure. The paper concludes with an introduction to an enhanced software that incorporates this new modeling technique for collapse prediction.
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