bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Insight into Failure of Resin-Coated Proppant Consolidation
Authors: Dewprashad Brahmadeo , Nguyen Philip D. , Weaver Jimmie D. , Wardall Tom , Black Kathy 
Published: December 2007

Abstract
Operators use curable (precoated or on-the-fly coated) resin- coated proppants (RCPs) for controlling proppant flowback after hydraulic-fracturing treatments and in screenless, fracpack completions. A very important but much ignored consideration when choosing an RCP for a particular treatment is the cure kinetics of the proppant. This paper presents the results of a study to compare the consolidation performances of RCPs with different cure kinetics under simulated treatment and downhole conditions of extended pump times and delayed or insufficient fracture closures throughout packs. Techniques developed for determining RCPs' cure kinetics are described. These techniques include differential scanning calorimetry (DSC), rock-mechanical measurements, and scanning electron microscopy (SEM). The cure kinetics of different RCPs are related to their consolidation strengths and photomicrographs obtained of these proppants after they are subjected to conditions simulating different times before onsets of closures at bottomhole temperatures (BHTs).
SEM micrographs showed that in the faster-curing RCPs, there was a dramatic decrease in the numbers and areas of contact points between proppant grains. These micrographs correlate well with the losses of consolidation strengths determined when faster-curing RCPs were exposed to fluids at temperature for various times before onsets of closures. For consolidations simulating wells with high BHTs, the losses of consolidation strengths were more severe, and the numbers and areas of contact points decreased.
This study provides dramatic new answers as to why many RCP consolidations might have failed in the field. Operators can use the information presented to help themselves select the best RCPs for their applications. The information presented is particularly useful for selecting the RCP to be used in screenless completions where consolidations are expected to withstand production conditions of high flow rates and stress cycling. This study improves understanding of the failure mechanisms of RCPs and provides guidelines for proper design and candidate selection for proppant-flowback control and for screenless completions.
P. 347
Reservoir Engineering Analysis of Pincher Creek Gas Field Performance
Authors: Ambastha A.K. , Chornet M. , Beliveau D.A. 
Published: December 2007

Abstract
Pincher Creek gas field, located in south-western region of Alberta, was discovered in 1947 by Canadian Gulf Oil. Pincher Creek gas field is a low-permeability, naturally- fractured, carbonate reservoir. Production from this field started in Jan. 1957. A total of 27 wells have been drilled in this field. However, only six wells are still producing from this reservoir. Many wells in this field have experienced shortened producing life because of water-related problems.
Initial gas-in-place and remaining reserves are reported as 46.8 and 1.5 BCM, respectively, in Alberta Energy and Utilities Board (AEUB) 1994 publication of reserves. Cumulative gas production to the end of Dec. 1996 has been 14.5 BCM. Thus, Pincher Creek gas field seems to have a very low recovery factor. Forty years of production data have been analyzed using conventional material balance, decline curve analysis, and communicating reservoir model to verify initial gas-in- place and reserve estimates for the Pincher Creek gas field. These analyses have led to definitive and consistent initial gas- in-place and reserve estimates for this field.
Efforts have also been made to understand water production mechanisms in this field. Analysis shows that water production behavior in this field is neither related to permeability distribution from core analysis nor to the distance from the bottom of perforation to gas-water contact. Diagnostic plots of the Cartesian derivative of water-gas ratio versus time have shown promise in identifying water production mechanisms for the wells in this field.
P. 367
Development and Application of Kinetic Hydrate Inhibitors in the North Sea
Authors: Phillips N.J. , Grainger M. 
Published: December 2007

Abstract
Low dose kinetic hydrate inhibitors, developed as an alternative to thermodynamic inhibition of gas hydrates, are a branch of specialty treatment chemicals that is still considered "novel". Such inhibitors have only been a commercially viable alternative to hydrate prevention treatment in the last three years. During and subsequent to this kinetic inhibitors have been deployed and developed successfully for both mature assets and new developments in the North Sea. The kinetic inhibitors developed are termed Kinetic Hydrate Inhibitors, or KHI. Currently a KHI is being successfully deployed in the Hyde West Sole system in the Southern North Sea, and in May of 1998 the Eastern Trough Area Project (ETAP) will start up operations and will use KHI from day one of production.
Much has been learned from the development and introduction of KHI products with careful consideration being given to any potential effect that will compromise, not only the production operations, but also the efficacy of any additional additives. Experience has shown that each system must be treated as an individual and the inhibitor tailor made to suit. Here water chemistry, gas composition, temperature, and application all play a major role in the decision process. The use and application of this information, enabling the selection of the most appropriate material can be termed as a complete systems approach. This paper highlights the rationale behind this approach and elaborates on the aspects associated with the deployment of KHI, that experience has shown to be major limiting factors.
P. 397
Permeability Reduction by Treatment with KUSP1 Biopolymer Systems
Authors: McCool C.S. , Shaw A.J. , Singh A. , Bhattacharya S. , Green D.W. , Willhite G.P. 
Published: December 2007

Abstract
The application of KUSPl biopolymer for use in permeability reduction treatments of oil reservoirs was investigated. KUSPl is a non-toxic polysaccharide that is produced by a bacterium. Alkaline solutions of KUSPl have low viscosities and can be gelled by different methods. Three methods were examined to gel KUSPl in porous media. Two of the methods are based on the reduction of pH of alkaline KUSPl solutions. KUSPl is soluble in alkali but forms a gel when the pH is lowered to values below 10.8.
The first method employed the hydrolysis of an ester to reduce pH and trigger gelation. Gel times on the order of days were observed for KUSPl solutions that contained the monoethylphthalate (MEP) ester. The performance of the KUSP1-MEP system in treatments of sandpacks, Berea cores and carbonate field plugs was studied at 25 C. Brine permeabilities were reduced by factors that ranged from 75 to 4500. Permeability reduction by treatments with the KUSPl MEP system was stable to brine flow for periods of up to six months.
The second method to gel alkaline KUSP1 solutions was based on the chemical interactions with rock material. It was found that interactions with Berea sandstone, Baker dolomite, silica sandpacks and field core plugs were insufficient to reduce the pH of alkaline KUSPl solutions to values required for gelation.
Alkaline KUSPl solutions were gelled by the addition of boric acid in the third method. Bulk gelation studies conducted at 25, 45 and 65 C showed that gel times could be regulated up to several days by selection of pH and boric acid concentrations. The gels were more rigid than those produced by pH-reduction methods, indicating a different gelation mechanism. Syneresis was observed and was more pronounced at lower pH values and higher temperatures. The KUSP1-boric acid system reduced brine permeabilities in sandpacks and Berea cores (25, 45 C) by factors that ranged from 50 to 3300.
P. 493
California Gas - Quo Vadis?
Authors: Lippitt Henry F. 
Published: December 2007

The supply of oil well gas has dropped sharply in southern California, and the supply of dry gas is barely holding its own in northern California—in the face of an unprecedented national shortage. Why this dismal picture? What, if anything, are the gas distributors, Los Angeles City Council, the Public Utilities Commission, Supervisor of Oil and Gas, the State Lands Commission, or the Secretary of the Interior doing to help?

Natural Gas Supply

(a) Average Daily Supply
Although the first supplies of out-of-state gas did not arrive in California until 1947 (Southern California) and 1949 (Northern California), and the first supplies of Canadian gas did not arrive until 1961 (Northern California), out-of-state and Canadian gas supplies account for over 75% of the State's gas consumption. Today, only about 20% of the State's supply comes from California produced gas sources: about 25% in Northern California, and only about 16% in Southern California.
Southern California (1971)* Approximate % Of Sources of Supply (Bcf) Mcf/Day Total
California Gas Regular Purchases 133,810 366,600 11.9% Exchange Gas 33,056 90,600 2.9 Federal Offshore 15,545 42,600 1.4 Total California 182,411 499,800 16.2%
PG and E Purchases 58,780 161,000 5.2% El Paso 608,830 1,668,000 54.2 Transwestern 273,798 750,100 24.4 Total 1,123,819 3,078,900 100.0%
Northern California (1971) Approximate % Of Sources of Supply (Bcf) Mcf/Day Total
California 258,064 707,000 25.5% PGT (Canada) 341,287 935,000 33.7 El Paso 414,231 1,134,900 40.8 Total 1,013,582 2,776,900 100.0%

(b) Type of Supply
Generally speaking, the available supplies of California produced gas may be divided into two categories:
The Effects Of Various Reservoir And Well Parameters On Water Coning Performance
Authors: Byrne William B. , Morse Richard A. 
Published: December 2007

1973 Third Symposium on Numerical Simulation of Reservoir Performance Houston, Texas January 11–12, 1973

Abstract
Most research on water coning has been directed toward minimizing water production by reduced well penetration or production rate control. However, complete depletion of an oil column underlain by water will necessarily be accompanies by considerable water production, at least in the latter stages of depletion. By means of numerical simulation a systematic study was made of the effects of reservoir and well parameters on water coning performance. Included were the effects of aquifer thickness, well penetration, pressure drawdown, and horizontal to vertical permeability ratio. permeability ratio. These studies revealed that higher water-oil ratios, at every stage of depletion, resulted from increasing well penetration or increasing pressure drawdown at the producing well. Accompanying the increase in pressure drawdown at the producing well. Accompanying the increase in water-oil ratio is an increase in oil production rate of the same magnitude thus decreasing the operating life of the well. There is no indication that the ultimate oil recovery is adversely affected by increased production rates. As a matter of fact it appears that high production production rates. As a matter of fact it appears that high production rates could lead to improved economic oil recovery. Produced water-oil ratio at every stage of depletion is strongly influenced by the ratio of horizontal to vertical permeability and to a lesser degree by aquifer thickness.

Introduction
Water coning, during which bottom water gradually or abruptly breaks into an oil- or gas-producing well, has long been a problem in oil fields. It is a very complex problem and has been investigated by many researchers.
A System for Formation Evaluation Under North Sea Conditions
Authors: Stewart D.I. , Fordham P.A. , Kisling J.W. , Nutter B.P. 
Published: December 2007

This paper was prepared for the Second Annual European Meeting of the Society of Petroleum Engineers of AIME, to be held in London, England, April 2–3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
A new test system for floating vessels uses annulus pressure control to operate down-hole valves. A nitrogen-charged test valve senses the change in annulus pressure to provide positive well control at all times. A correction system is included to provide reliable operations over a wide range of pressures and temperatures. A sampling chamber is available with a complete set of accessory tools for safe testing. The results of field testing are included.

Introduction
A drill stem testing system for floating vessels has been introduced in the rough conditions of the North Sea and has given satisfactory results in this environment. The system uses a Pressure controlled Test Valve known as Pressure controlled Test Valve known as the PCT valve. When pressure is applied to the annulus (in excess of the hydrostatic pressure), the test valve opens. The valve recloses when the pressure is released. This allows the operator to conduct a test with the minimum of pipe manipulation. This avoids the problems of trying to position down-hole tools accurately while the vessel is moving up and down due to wave action. The system includes a complete line of accessory equipment to provide positive well control through redundancy of all valve functions, to ensure that the reservoir can be adequately tested in complete safety.

EQUIPMENT AND OPERATION

Tool System
The heart of the system is the Pressure controlled test (PCT) valve. Pressure controlled test (PCT) valve.
From Theory to Practice: Evaluation of the Stress Distribution for Wellbore Stability Analysis in an Overthrust Regime by Computational Modelling and Field Calibration
Authors: Last N.C. , Harkness R.M. , Plumb R.A. 
Published: December 2007

Abstract
Faced with significant operational problems, this paper describes how a novel application of computational mechanics was used to help to evaluate and gain insight into the stress distribution in the drilled rock volume above the Cusiana Field in the geologically complex foothills of the Eastern Cordillera of the Andes, Colombia, South America. This has contributed to improved understanding of the causal effects of poor hole condition and drilling difficulties, and provided the basis for the development of a mud weight planning tool. Improved drilling performance has lead to savings of millions of dollars.
P. 49
Two-Phase Flow Simulation of Mud Pressure Penetration
Authors: Naseby D. , Yang Z. , Rahman S. , Tan Chee 
Published: December 2007

Abstract
One of the key time-dependant mechanisms for wellbore failure in shales is the penetration of drilling mud into the formation. Previous studies attempted to predict mud pressure penetration into shales using single-phase flow approach. This can lead to some errors because it ignores the two-phase flow and capillary effects. In this study, a numerical model has been used to study fluid flow in shales. For modeling of two-phase flow, relative permeability curve was calculated using modified Corey's method, which is based on pore size distribution. The pore size distribution of shales was quantified by using mercury injection tests. It has been observed that the two-phase flow model can predict mud pressure penetration reasonably well when the permeability of shales is relatively high (k is greater than 500 nD). This approach has an application for the prediction of mud pressure penetration in shales with drilling induced or natural fractures, which may significantly enhance shale's permeability. It was also found that the two-phase fluid flow model, even possibly Darcy's law in general, may be inadequate when shale's permeability is low and the pressure differential is high. Possible explanations are that shales have a complex structure, with different types of water present, and predominant surface interactions, which may change shales' permeability significantly, thus making Darcy's law inadequate. Future work is recommended for investigations into fundamental laws governing fluid flow in shales in order to improve the prediction of time-dependent wellbore instability in shales.
P. 115
Does the Seasoning Procedure Lead to Intrinsic Properties?
Authors: Bouteca M.J. , Bary D. , Fourmaintraux D. 
Published: December 2007

Abstract
In laboratory experiments, an evolution of the measured rock properties is often observed when the core undergoes cyclic solicitations. There is still a debate in order to define which value should be chosen, and basically the question is to define which value is intrinsic to the rock and which value should be considered as an artifact. Experiments have been performed on a reservoir sandstone and 9 loading cycles have been applied. It is shown that the sandstone behavior can be fully described using Biot's semi-linear poroelasticity. Within this theoretical framework, it is shown that cyclic loading leads to intrinsic values of the rock constitutive law.
P. 321
Characterization of Flow Within Natural Fractures: Numerical Simulations and Field Applications
Authors: Bertuzzi F. , Sanfilippo F. , Brignoli M. , Parravicini G. 
Published: December 2007

Abstract
Natural fractures are commonly encountered in several Oil Industry related activities: one has to think, for example, to mud losses or lost circulation problems when drilling fractured formations. In the same way the characterization of porosity and permeability is one of the most difficult task when dealing with naturally fractured reservoirs. In fact these properties depend on parameters which cannot be known with direct measurements, such as the geometric characteristics of the single fractures, their density, the extension of the networks they form, etc. Moreover, the conductivity of natural fractures depends on the physical mechanisms which govern the flow within them and, during the exploitation of the reservoirs, can diminish due to the increase of the effective stresses which tend to close the fractures.
Recently Eni/Agip has presented a methodology which characterizes the conductivity of the open fractures using real time monitoring of mud loss data while drilling. Starting from this previous work, a detailed characterization of single-phase flow within natural fractures has been performed via numerical simulations and analytical models. In particular, the effect of the geometric properties of the fractures (aperture, tortuosity and roughness) on the flow pattern and on the average conductivity have been investigated. The main results can be summarized as follows;
– validation of the hypothesis of the laminar flow in the description of the flow dynamics in a small fracture; – development of flow patterns characterized by the presence of areas of high permeability that can be seen as network of channels; – correction of the so-called cubic law for hydraulic conductivity through the measure of the fractal dimension of the fracture surface.
Moreover, as it is shown with field examples, the interpretation of mud loss data on the basis of the acquired knowledge allowed to achieve a better evaluation of the near- well conductivity. These facts will provide more reliable and useful information when examining mud losses problems, and consequently the way to solve them, and are of primary importance for the first evaluation of productive intervals and for their selection for testing, completing, etc
P. 337
The Method of Reducing Drilling Costs More Than 50 Percent
Authors: Gjelstad G. , Hareland G. , Nikolaisen K.N. , Bratli R.K. 
Published: December 2007

Abstract
This paper shows how using the Drilling Gptimization Simulator (DROPS) has been applied in the planning phase of two North Sea wells. Both the 12.25" and the 8.5" sections were optimized on Well #1 and the 12.25" section was optimized on Well #2. Geological Drilling Logs (GDLs) were generated from offset drilling data in the same field for both the two wells. Both wells with the different hole sections were simulated with the available bit types and designs. The optimum bit selection and the drilling parameters every meter for the hole-sections were optimized. The hydraulic limitations of the pump and the planned mud weight program were used to optimize the bit hydraulics in conjunction with the bit operating parameters, different pull depths and bit designs. The 12.25" sections showed savings potential of 72.4 percent on Well #1 compared to the last well drilled in the field. This included optimizing bit type, hydraulics, operating parameters and pull depths. Well #2 showed savings potential of 15 percent using oil based mud and 20 percent using water based mud compared to the two other wells drilled previously in the field with oil and water based mud respectively. It was concluded that Well #1 could save $ 1.3 million, while Well #2 was originally drilled close to optimum and only showed a potential savings of $ 0.3 million when using optimum drilling parameters.
The optimization of the 8.5" section was more complex because of several coring intervals. The five full hole sections between the coring intervals were optimized. The five subsections were drilled through formations of different length and lithology. The bit designs, pull depths, number of bits, hydraulics and operating conditions were optimized for each section. In addition to optimization of the drilling parameters, simulations for reuse of bits were conducted to further cut the drilling costs. The cost savings on the 8.5" section for well#1 showed a maximum potential for saving varying from 23.4 to 78.8 percent for the different sections.
From the simulations it can be concluded that the optimum drilling scenario of the 12.25" and 8.5" fitll hole sections for well #1 would reduce the drilling cost with more than $ 4.5 million.
P. 161