bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach in Modeling Asphaltene Precipitation in Heavy Oil
Authors: Nikookar M. , Pazuki G. H. , Masoudi R. 
Published: December 2007

Abstract
Asphaltene Precipitation is a perennial problem in production of heavy oils. Field condition conducive to precipitation includes normal pressure depletion, acid stimulation, gas-lift operation, and miscible flooding, just to mention a few. To avoid precipitation, it is useful to know the solubility of asphaltene in petroleum liquids as a function of temperature, pressure, and liquid-phase composition. The accurate prediction of phase behavior in multi-component hydrocarbon systems prone to asphaltene precipitation is, therefore, crucial for the economic and safe operation of any petroleum production scenarios.
In this study, the Soave-Redlich- Kwong equation of state (SRK EoS) has been modified based on perturbation theory in order to improve the phase behaviour predictions and develop a more flexible EoS to modeling asphaltene precipitation. The parameters of the new cubic equation of state considered to be reduced temperature and acentric factor dependent. These parameters have been determined using three phase behaviour calculations namely, saturated vapor pressure, vapor volume and saturated liquid density, for 40 pure hydrocarbon and non hydrocarbon compounds with an absolute average deviation percent of 0.814, 2.614 and 5.814, respectively.
Next, applying the newly modified EOS, the Flory-Huggins (FH) model is adjusted to predict asphaltene precipitation more accurately. The adjustable parameter is defined based on solubility parameter of asphaltene in heavy oil. The phase behavior of asphaltene was extended by these modifications and the precipitation of asphaltene is calculated while adding three n-alkenes solvents. The newly developed model predictions for amount of asphaltene precipitation have been compared with Flory-Huggins model as well as available literature data, showing the robustness and reliability of the new approach.
Successful Application of Viscoelastic Fluid Technology to Stimulate a Gas Storage Reservoir
Authors: Fry L. , Stegent N. , Amos J. , Martin J. , Silber R. , Young U. 
Published: December 2007

Abstract
Columbia Gas Transmission operates two groups of natural-gas storage fields approximately 50 miles northeast of Columbus, Ohio. The Silurian-age Clinton sandstone formation in both fields varies significantly in thickness and reservoir quality. Although the gross Clinton interval is fairly uniform, it can include one to three separate sand members.
Reduction in storage-well performance over time dictates the need to periodically stimulate, or even re-stimulate the wells. Fracture stimulation is often required to restore well performance. The objective of the hydraulic fracturing treatments in these wells is to obtain a short, highly conductive propped fracture past the damaged area. Fracturing models are used to determine the optimum tip-screenout treatment design based on individual well characteristics.
Several fracturing fluids have been used in the attempt to achieve the optimum fracturing treatment. Previously, the best results were seen with borate-crosslinked fluids using nitrogen assist. With recent advances in fracturing-fluid technology, conventional borate-crosslinked fluids can be replaced with high-performance viscoelastic fluids, which reduce fluid damage to the proppant pack and formation. The viscoelastic fluid has excellent proppant-transport properties and predictable break times.
Three wells, two in Group I and one in Group II, were selected as candidates for fracturing with the viscoelastic fracturing fluid. Fracturing models were used to design a treatment that would result in similar fracture geometry as the borate-crosslinked fluids. This resulted in up to 40% reductions in total fluid requirements and up to 65% reductions in pad fluid volumes. All three wells were fracture-treated with the designs obtained from the fracture models. Fluid volumes recovered, flowing pressures, and choke size were all recorded during flowback and compared to values from offset wells.
This paper details the properties of the viscoelastic fracturing fluid, fracture designs, and post-fracture results of the wells stimulated with the viscoelastic fluid.
Matrix Shrinkage and Swelling Effects on Economics of Enhanced Coalbed Methane Production and CO2 Sequestration in Coal
Authors: Gorucu F. B. , Jikich S. A. , Bromhal G. S. , Sams W. N. , Ertekin T. , Smith D. H. 
Published: December 2007

Abstract
Increases in CO2 levels in the atmosphere and their contributions to global climate change have been a major concern. It has been shown that CO2 injection can enhance the methane recovery from coal. Accordingly, sequestration costs can be partially offset by the value added product. Indeed, coal seam sequestration may be profitable, particularly with the introduction of incentives for CO2 sequestration. Hence, carbon dioxide sequestration in unmineable coals is a very attractive option, not only for environmental reasons, but also for possible economic benefits.
Darcy flow through cleats is an important transport mechanism in coal. Cleat compression and permeability changes due to gas sorption desorption, changes of effective stress, and matrix swelling and shrinkage introduce a high level of complexity into the feasibility of a coal sequestration project. The economic effects of carbon dioxide-induced swelling on permeabilities and injectivities has received little (if any) detailed attention.
Carbon dioxide and methane have different swelling effects on coal. In this work, the Palmer-Mansoori model for coal shrinkage and permeability increases during primary methane production was re-written to also account for coal swelling caused by carbon dioxide sorption. The generalized model was added to PSU-COALCOMP, a dual porosity reservoir simulator for primary and enhanced coalbed methane production. A standard five-spot of vertical wells and representative coal properties for Appalachian coals were used.1 Simulations and sensitivity analyses were performed with the modified simulator for nine different parameters, including coal seam and operational parameters and economic criteria. The coal properties and operating parameters that were varied included Young's modulus, Poisson's ratio, the cleat porosity, and the injection pressure. The economic variables included CH4 price, CO2 cost, CO2 credit, water disposal cost, and interest rate. Net present value analyses of the simulation results included profits due to methane production, and potential incentives for CO2 sequestered. This work shows that for some coal-property values, the compressibility and cleat porosity of coal may be more important than more purely economic criteria.
Testing Cement Static Tensile Behavior Under Downhole Conditions
Authors: Dillenbeck R. L. , GoBoncan V. , Rogers M. J. 
Published: December 2007

Abstract
Today's analytical models can calculate stresses imposed upon the annular cement sheaths of wells, and it has become apparent that induced stresses can often be tensile in nature. These models often predict the cement failing in tension as well. This understanding has caused the industry to step beyond API tests that only recognize methods for testing cement under compressional loads. Instead, the determination of cement tensile mechanical parameters should be considered as important as cement compressive strength. Unfortunately, with no API guidelines, most oilfield cement tensile behavior testing typically uses ASTM construction concrete test methodology. With oilfield cements, most ASTM tests suffer from various shortcomings. These can be traced to the fact that they are designed primarily to test construction cements that are not usually placed more than a few meters underground. These tests do not incorporate procedures to replicate the curing of the cement in downhole environments, and do not conduct the actual static tensile testing under conditions similar to those occurring in oil and gas wells. When oilfield cements are prepared and cured using API procedure in HTHP curing chambers, they must still be subjected to significant induced stresses as cooling and de-pressurization back to ambient conditions occur before they can be subjected to ASTM tests. Samples prepared and tested in such a manner may undergo sufficiently induced stress to exhibit physical signs of initial mechanical failure, prior to even being placed in ASTM testing fixtures.
To produce cement tensile behavior data that is more reflective of actual downhole performance, the authors developed an automated, microprocessor controlled testing device that cures and mechanically tests the cement under simulated downhole conditions. Once slurry is placed in the testing device, and the temperature and pressure is ramped up to simulate downhole curing conditions, the samples never see ambient conditions again until the conclusion of testing. The microprocessor controls and automated data acquisition unit also allow for the determination of tensile stress-strain relationships, prior to testing the sample to ultimate (mechanical) failure in tension.
In this work, the authors present detailed descriptions of the operational capabilities of the new testing device, along with data developed with the device. Using the tensile data developed under more realistic downhole conditions, induced stress models can now generate even more accurate predictions about fit-for-purpose cement designs for wells of all depths and applications.
Long-Term Gas Storage Deliverability Improvement from Fracturing and Refracturing Treatments Using a Proppant Surface Modification Agent
Authors: Guoynes J. , Kozera G. A. , Shaw J. S. , McCallister J. 
Published: December 2007

Abstract
This paper presents long-term follow-up results from post-fracture and post-refracture deliverability testing for 56 gas storage wells. The wells studied include 32 injection/withdraw (IW) wells hydraulically fractured with surface modification agent (SMA) applied to the proppant and 24 IW wells hydraulically fractured without SMA applied to the proppant for sand flowback control.
Deliverability sustainability results previously presented1 will be updated for these treatments from a 6- to a 9-year period. The results will include analysis from deliverability data for SMA-treated and non-SMA-treated wells over six to nine IW cycles. Three wells of the original group of 24 wells previously fractured without SMA were refractured using SMA.
In the original study, a number of wells were fractured without using SMA proppant. These earlier stimulation treatment wells suffered some operational problems and the need for proppant flowback control became apparent. The addition of SMA to fracture treatments reduced operational problems related to produced sand and fracture treatments improved deliverability. The wells that included a SMA now have been through six to seven complete pressure cycles and the long-term effects of sand flowback and well performance can be compared.
The results of this updated study show that SMA injected with the proppant helps reduce operational problems in gas storage fields by reducing proppant flowback. In addition, analysis of SMA fractruring treatments in gas storage wells typically show no detriment to long-term performance. In addition, SMA can improve results from refracturing.
Cold Heavy-Oil Production at Patos-Marinza, Albania
Authors: Weatherill B. D. , Seto A. C. , Gupta S. K. , Çobo L. 
Published: December 2007

Abstract
The Patos-Marinza Heavy Oil Field, located in southern Albania, was discovered in 1928. The reservoir, with oil specific gravity ranging from 0.86 to 1.05 (3 to 33 °API), contains one of the largest onshore oil resources in continental Europe. Primary production commenced in the 1930s and reached a peak rate of over 3,300 m3/d in the late 1950s. By June 2004, over 2,400 wells had been drilled, at an average spacing of about 3.6 hectares, and cumulative oil production amounted to about 19 million m3. However, the expected ultimate oil recovery by primary recovery was only about 6% of the original-oil-in-place (‘OOIP’).
In 1999, foamy oil production was successfully tested in the laboratory for field application at Patos-Marinza. Subsequently, progressive cavity pumps (‘PCP’s) were installed in 12 wells in the northern region of the field completed in the main Driza sands, as a pilot test of Cold Heavy Oil Production (‘CHOP’) technology to improve recovery. In July 2004, an intensive campaign of well reactivations using CHOP technology was initiated under new operatorship.
The performance of the pilot test indicated that foamy oil behavior had been clearly initiated at 5 of the initial test wells as a result of the increased drawdown applied to the reservoir. Oil production rates were increased significantly, by an order of magnitude, between 10 m3/d and 20 m3/d. In addition, sand cuts of between 5% and 20% and foam cuts were reported.
The performance of the wells put on CHOP production since change of operatorship in July 2004, have yielded good results. As of July 2005, the current operator has taken over 76 wells and continues to progressively apply CHOP technology to the field. This paper focuses on the wells that have exhibited clearly defined CHOP performance characteristics and reports the initial results in terms of well production rate responses.
Large-Scale Laboratory Investigation of the Effects of Proppant and Fracturing-Fluid Properties on Transport
Authors: Brannon H. D. , Wood W. D. , Wheeler R. S. 
Published: December 2007

Abstract
The primary function of fracturing fluids is to provide the means and media for the transport and placement of a conductive proppant pack in the created fracture such that resident hydrocarbons may be more easily produced. In recent years significant effort and expense has been invested to develop an ideal fracturing fluid system. Such efforts have been often been akin to the proverbial dog chasing his tail, rather than on the addressing the engineering objective to place a conductive propped fracture. Development focus has been primarily on optimization of fluid rheological stability to get the treatment pumped and secondarily to mitigating any damage caused by new fluid system. Post-frac production analysis frequently demonstrates less than anticipated fracture area, suggesting excessive proppant-pack damage or that the proppant was not placed in designated areal location due to inadequate proppant transport.
Recent testing was conducted in a large-scale slot apparatus at the Well Construction Technology Center in Oklahoma to evaluate the relative effects of proppant slurry component characteristics and the proppant transport capability. The effects of various fluid specific gravities, fluid viscosities, proppant specific gravities, proppant sizes, slurry flow rates, and slot widths were investigated. Testing included fluids from slickwater to gelled, weighted brines, proppants from 40/70 Ottawa sand to 14/30 ultra-lightweight proppants, pump rates from 0.1 to 1.0 bbl/ft/min, and slot widths from 0.25 to 0.5". Evaluation of the proppant transport testing data and the comparative abilities of current fracturing slurry system technologies to achieve placement of a productive propped fracture will be discussed.
High-Temperature Multiphase Flowmeters in Heavy-Oil Thermal Production
Authors: Mehdizadeh P. 
Published: December 2007

Abstract
The accurate measurement of Oil, Water and Gas/Steam in heavy oil thermal production (SAGD and other Steam Flood Processes) is a very difficult task faced by the heavy oil industry. The accuracy of these measurements is critical for reservoir management and production diagnostics. Mulitphase flow meter technology has been used successfully around the world for over 10 years and in heavy oil "cold" production in Venezuela and other countries. But multiphase technology has never been used in Extra Heavy Oil Thermal Production. The Canadian heavy oil thermal producers regularly see production temperatures exceeding 200 C (392 F) and some wells are approaching 232 C (450 F). New technology is required to accurately measure wells producing at these elevated temperatures. The first field tests using a multiphase flow meter in a heavy oil thermal project was conducted by one of the major Canadian producers in the fall of 2004. Additional tests were completed during the summer of 2005 with another heavy oil producer. This paper will review the unique problems encountered with testing heavy oil in high temperature applications. The test results from multiple well tests and the accuracy of the multiphase flow meters when compared to the field reference will be presented.
Successful Rescue of a Sunken Oil Well With Innovative Coiled-Tubing Solution
Authors: Mahajan M. , Al Araimi N. , Portman L. , Terry A. 
Published: December 2007

Abstract
A 36" conductor had been set in 40m of water, offshore Brunei. A jack-up rig was being used to drill two wells through this single conductor. The first well (Well-A) was completed successfully with a smart completion in a 7" liner. The second well (Well-B) was under construction. Multiple millions of dollars had been spent on these two wells. It is at this point that the 36" conductor sank by 15 inches. This slumping of the conductor was enough to cause a failure of the well under construction (13-3/8" casing failed and the Drill string was lost in hole) and severe buckling in the already completed well. This event had potentially rendered the entire operation as nonproductive. Both 13 3/8" casings were cemented into the 36" conductor. The operator was desperately looking for any ideas to save the first well, which was expected to produce some 5000 BOPD.
This paper describes the thought processes, engineering and the job execution techniques involved with the rescue of this well. The cement bond between the casing and the conductor was removed and the casing was successfully re-tensioned. Several innovative techniques were utilized, using coiled tubing, a down hole camera and hydraulic jacks. This paper is intended to share the knowledge gained during this unusual intervention, which successfully brought the well on stream with initial gains of 5,000 BOPD.
Safety Is No Accident
Authors: Mahajan M. , Al Araimi N. 
Published: December 2007

Abstract
Well drilling and service operations generally involves heavy machinery, bulky equipment, heavy lifts, hazardous chemicals, challenging well conditions & worksites and tougher logistical elements. All these elements pose a challenge to the achievement of QHSE performance levels the oil and service companies aspire to achieve today. Over recent years, there has been a lot of learning, understanding and research work into these areas. These, coupled with a tremendous shift in awareness and attitudes towards the QHSE aspects of business, both in the operator and service sectors of industry, have brought in noticeable changes in the business environment. The role of QHSE performance now a days is not only limited to social dimension but it has become very decisive factor in the ultimate financial success of any business entity.
In Feb 2005 a major international operator in the Asia Pacific achieved a milestone of 6+ years LTI-free coiled tubing/well servicing operations. Considering that each and every job conducted throughout this six year period involved some combination of the several high potential hazards as stipulated above, this is indeed an achievement to be proud of.
A critical review of the whole process has been attempted in this paper to identify and highlight the critical components, which have played vital roles in the achievement of this great milestone. It is demonstrated that Safety is no accident; it is something we achieve by hard work, deep dedication, tremendous efforts and relentless follow-ups. We believe that the learning from this study would greatly contribute to improvements in safety performance of similar operations worldwide.
Optimization of Hydraulically Fractured Wells in Irregularly Shaped Drainage Areas
Authors: Daal J. A. , Economides M. J. 
Published: December 2007

Abstract
In using hydraulically fractured wells for aggressive reservoir exploitation, the spacing of vertical wells and/or transverse fractures in long horizontal wells becomes quite an important consideration. The geometry and conductivity of single fractures in infinite-acting reservoirs have been related to productivity by the well known Cinco-Ley and Samaniego work. Later work by Valkó and Economides provided physical optimization under pseudosteady-state conditions in regularly shaped (circular or square reservoirs) using the novel concept of the Proppant Number as a normalizing and descriptive parameter.
However, the shape of the drainage is rarely square and, especially it is not so when a given drainage area is split by the drilling of in-field vertical wells or, in the case of a horizontal well, multiple transverse fractures are executed. The shape of the drainage, encompassing parallel, tightly spaced fractures, becomes a controlling variable for the calculation of the individual and total productivity indices. This is particularly important in our quest to maximize well performance, not just to fracture wells. Until now, such work was the realm of numerical simulation with all the associated benefits and problems.
In this work, the pseudosteady-state productivity index of a fractured well in reservoirs with different aspect ratios (ye/xe) was calculated using the Direct Boundary Method. For relatively small Proppant Numbers, there is a simple relationship that allows for the use of already developed correlations by Valkó and Economides for maximum productivity index and optimum fracture conductivity (and the indicated fracture geometry). For larger Proppant Numbers, this work provides factors labeled Fopt that account for the departure from the square optimum. These factors facilitate the calculation of the maximum JD in different reservoirs for any Proppant Number. The work allows for drainages of a large range of aspect ratios and any fracture penetration.