bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Cases to Demonstrate Application of through Tubing Inflatable Anchoring Packer to Selectively Stimulate Vertical Dump Water Injector Wells with Cross Flowing Zones
Authors: Al-Dubais A. M. , Kharari A. H. , Jemmali M. , Al-Hadyani F. S. , Wilson S. , Samuel M. 
Published: December 2007

Abstract
There are few methods to acid stimulate cross-flowing zones in dump water injector wells. Traditionally these wells are stimulated by bull-heading acid from surface or pumping it through Coiled Tubing (CT). The dilution and contamination of the acid while being injected into the formation resulted in no increase in dumping injection rates. Poor post stimulation results are confirmed by spinner survey logs done before and after the conventional acid treatments.
Through Tubing Inflatable Anchoring Packer (TTIAP), a new zonal isolation tool conveyed by coiled tubing was successfully used to selectively acidize the targeted zone by isolating the non-desired zones. TTIAP has an effective and reliable high pressure sealing properties at large inflation ratio. Its chemical resistance makes it ideal for selective placement of treating fluids, such as acid stimulation and water shut off fluids.&lt;sup&gt;1,2&lt;/sup&gt;
A non-polymeric Viscoelastic Surfactant based Self Diverting Acid (VES-SDA) system was successfully used to divert and effectively stimulate these vertical dump water injector wells by achieving uniform acid coverage across the whole perforated interval. The VES-SDA is a single stage fluid that has the capability to stimulate and divert in one step.
This paper discusses the successful application of TTIAP as a mean of mechanical diversion in the well-bore area to isolate between the "S" aquifer and the "R" reservoir, while VES-SDA acid was used as a mean of chemical diversion inside carbonate formations. The injection evaluation logs showed significant injection rate increase after the new stimulation method.
This study marks the first time such a combination was used to stimulate dump water injector wells with crossflowing zones in Saudi Arabia.
Hydraulic Fracturing of Polymer Injection Wells
Authors: Yan Wang , Demin Wang , Zhi Sun , Changlan Shi , Gang Wang , Desheng Li 
Published: December 2007

Abstract
Polymer flooding is of strategic importance to Daqing Oil Field. At present, the oil production by polymer flooding is more than 12 million tons per year. However, some problems still need to be solved; fracturing in polymer injection wells is one of these problems. After fracturing more than 40 polymer injection wells by conventional methods, the results show that the effective period of fracturing is less than 3 months. This paper focuses on the reasons of this phenomenon (short effective period), how to solve this problem, what is the best operation procedure in the field and does it suit water injection wells also.
From lab tests, it was found that under high injection pressure, the proppant in the fracture can propagate forward (especially when injecting high viscosity fluids), thereby causing the fracture near the well bore to close and the frac job to fail in a very short time. Lab and well site tests show that using resin coated sand (the proppant is adhesives together in the fracture to form a very porous pancake and cannot propagate forward) can greatly increase the effective period of the frac job in polymer injection wells (from 3 months to 30 months). The results in the field of 97 polymer injection wells fractured by this method are analyzed by using injectivity index curves and compared to that of conventionally fractured injection wells. The results of 13 water injection wells are also analyzed, showing that they are very good also, the effective period of the frac job increased from 6 months to more than 24 months. Now, most of the frac jobs on injection wells (both polymer and water injection wells) in Daqing are stimulated using the method described in this paper. This method should also be of reference value to injection wells that have a short effective period to a frac job.
Fracture Propagation Prediction in an Openhole Horizontal Injector Well: An Applied Geomechanic Study
Authors: Chavez J. C. , McCurdy P. , Morgan L. 
Published: December 2007

Abstract
Understanding and predicting fracture propagation behaviour in a geotectonically complex, layered reservoir presents major challenges. In particular, an accurate prediction of vertical fracture extension in horizontal injection wells is fundamental to the overall waterflood injection performance assessment.
Water injection in an open hole horizontal well in a low permeability formation may generate one or multiple fracture planes depending principally on the orientation of the well with respect to the in situ stress field, as well as the combined effects of high injection rates, low injectivity and stress reduction due to thermal effects.
Conventional fracture generation prediction in horizontal sections considers predetermined areas where the fractures will propagate. In an open hole environment, the number of fractures that will be generated over time is often too complex to allow accurate prediction.
A novel methodology, based on a fracture energy dissipation approach, has been developed to overcome the problems associated with conventional models in horizontal open hole sections. This strategy integrates the field geomechanical model with a commercial transient fracture simulation model. The simulation model was used to predict the vertical extension of the fractures by studying the energy dissipation that takes place under specific injection conditions.
A relationship has been found between the initiation area, injection flow rate and the non-dimensional vertical propagation factor that can be used to predict (and ultimately control) vertical fracture growth even in heterogeneous sand-shale sequences. The introduction of selective initiation areas along the horizontal well section will radically improve the control of fracture vertical extension.
Using this methodology, it is possible to design and evaluate completion strategies, which optimise fracture energy dissipation and fracture containment performance in open hole horizontal injection wells in low permeability formations.
Wellbore Stability of Extended Reach Wells in an Oil Field in Sarawak Basin, South China Sea
Authors: Tan C. P. , Yaakub Mohd Azriyuddin , Chen Xi , Willoughby D. R. , Choi S. K. , Wu B. 
Published: December 2007

Abstract
The development plan of an oil field in the Sarawak Basin, South China Sea includes extended reach wells. Drilling experience in exploration wells highlighted the issue of wellbore instability in the region. A wide range of wellbore instability-related problems has been experienced, ranging from tight hole (remedied by reaming) to overpull and stuck tool, and a range of drilling fluid designs has been implemented. There was considerable concern regarding wellbore stability, including coal bed instability, its effect on drilling performance and the potential for this to severely impact both schedule and budget. Subsequently, a wellbore stability study, with an emphasis on extended reach wells planned for the field development, was conducted. The aim of the study was to develop a strategy to maintain mechanical and time-dependent stability of the extended reach wells to ensure the well construction encounters minimum wellbore instability-related problems. With the availability of additional well data and the need to push the technical limit of the drilling campaign, a follow-up review study was conducted and the additional information was used to refine the critical mud weight contour plots for a range of wellbore enlargements.
This paper describes the outline of the study, the approach adopted in the development of the strategies and the utilisation of the results from the two studies to develop recommendations for the mud weight programs. The drilling experience, material properties, typical in-situ stresses and formation pressure in the field are presented and discussed. Based on the gathered drilling experience, composite logs and laboratory tests conducted on downhole core materials, dominant failure mechanisms for the key formations and coal beds were identified. An empirical approach was adopted for the prediction of lower bound mud weights for wellbore enlargements ranging form 10% to 40% of wellbore diameter. Examples of critical mud weight contour plots and pore pressure change tables which form part of the strategy for designing optimal drilling fluid program are presented.
Distinct Element Analysis of Borehole Instability in Fractured Petroleum Reservoir Seal Formation
Authors: Nicolson J. P. W. , Hunt S. P. 
Published: December 2007

Abstract
This work presents the analysis of a borehole instability case at 2km in a seal formation within the oil field environment. Field observations of severe borehole instabilities are given. The factors causing this instability are observed as being due to cyclic mud pressure loading, drilling induced damage, wellbore orientation and fault set intersection at the wellbore.
Borehole breakout data both from image logs and calliper data has been used to determine the in-situ stress field. The minimum principal stress magnitude has been obtained using leak off testing, extended leak off testing through the analysis of borehole breathing during drilling with losses. The data has been analysed using non-parametric statistical techniques to determine the complete stress tensor. Fault property and in-situ rock mass data has been obtained from triaxial and shear box testing.
For this study the distinct element method (UDEC) has been used in 2D to study the wellbore stability under dynamic (fluid flow) conditions. Factors taken into account include fault, fracture and bedding surface orientation, fracture parameters, in-situ stress conditions, cyclic mud pressure loading, initial drilling induced damage and well bore orientation. The study has investigated the behaviour of a synthetic rock mass containing low permeability rock blocks separated by low to very low permeability joints.
It has been observed that all parameters influence the level of stability but using a prolonged delay in mud pressure reduction, stability can be maintained, also it is possible to select optimum wellbore orientation in advance using the numerical procedures.
A Case Study of Massive Hydraulic Fracturing in An Ultra-deep Gas Well
Authors: Ding Yunhong , Jiang Tingxue , Wang Yongli , Ping Sun , Xu Zejun , Wang Xin , Zeng Bin 
Published: December 2007

Proposal
A case study of hydraulic fracturing has been performed in details in Jing-70 gas well located in north china oil field with the depth larger than 4000 meters. In the past, such kind of gas wells couldn't be fractured successfully as a result of early tip-screenout.Our study is on the base of past fracturing experience, and a lot of improvements have been made. The main character of our fracturing design is as following:1)core test of stress sensitivity is used in performance prediction model and determination of bottom flowing pressure;2) mini-frac is performed in order to get loss coefficient more precisely;3)large scale of proppant volume and high proppant concentration are used as principles;4)a new surfactant named DL-10 is developed to increase flowing back velosity;5)long term conductivity is inputted in to a new developed gas reservoir model so as to perform optimization more scientifically;6)multi-stage proppant pumping schedule is used so as to get an expected propped profile;7)pumping rate is requested to increase higher and higher under the limit of wellhead pressure according to three dimensional fracture propagation model;8)liquid nitrogen is used in the course of fracturing in order to enhance flowing back of fracturing fluid after shut-in;9)forced closure technique is utilized;10)systematic field quality control is used to ensure fracturing treatment to follow the design plan, and some modifications is allowed according to the change of treatment situation.After that, the well is hydraulically fractured successfully with 67 tons of proppant and sand to liquid ratio as high as 30%,which is the highest record in ultra-deep gas wells in north china. And post evaluation is performed completely including net pressure analysis. Overall, the fracturing design, treatment and post evaluation discussed in the paper for ultra-deep gas wells has a great significance in gas wells’ stimulation and development as well.
Downhole Formation Fluid Identification in a Mature Multi-Layer Reservoir: A Case Study of an Advanced Wireline Formation Tester and Operational Practices for Highly Depleted Reservoir Evaluation
Authors: Ferment Denis , Gautama Yudowicana , Rourke Marvin , Guergueb Nacer , Singh Jorawar 
Published: December 2007

Abstract
The highly complex, stacked and multi-layered gas reservoirs found in the Mahakam delta of East Kalimantan present a challenge for both drilling and formation evaluation. Many of the mature producing reservoir layers are at low pressure today; but the presence of certain over-pressured intervals means drilling is essential with high mud weights. Drilling with high mud weights can lead to high differential pressures, as much as 5000 psi, between the wellbore mud system and the formation fluid pressures. A significant part of the formation evaluation in the Kutei basin [h1]requires formation fluid identification using a pumpout wireline formation tester (PWFT). The primary objectives are to obtain a measurement of the formation pressure, identification of the formation fluids, and the determination of fluid mobility. The PWFT tool operates by controlled pumping of formation fluid from a sample probe, which is positioned adjacent to the reservoir interval, through a fluid analyzer and out to the wellbore. Fluid property measurements and filtrate contamination and identification are accomplished with a new Magnetic Resonance Imaging Laboratory (MRILab™) fluid analyzer. Due to the difficult conditions encountered in the Mahakam delta, the sampling times ordinarily required to pumpout and collect uncontaminated PVT samples were not possible. This paper demonstrates the techniques that were developed where the MRILab could quickly identify the formation fluid in situ while pumping and eliminate the need to collect and retrieve a sample.
In this paper, we use field examples from operations involving the Reservoir Description Tool (RDT™) and the MRILab™. The RDT tool employs new features that enable enhanced operational practices to improve formation testing in this difficult environment. The tool features demonstrated in this paper include dual probes vertically spaced seven inches apart with isolation valves and independent pressure gauges for each probe, a new pump module that can operate up to 6000 psi differential, and an MRILab fluid analysis module. Operational practices discussed include preventing tool plugging, faster testing in tight zones, and precise tool positioning.
Integration of LWD and Wireline Array Technologies to Improve Estimation of Hydrocarbon Reserves
Authors: Frenkel Michael A. , Nuic Ivo , Walker Mike J. , Wolters Frank L. 
Published: December 2007

Abstract
This paper presents a new method for determining formation resistivity via sequential interpretation of the LWD and Wireline (WL) resistivity logs. The LWD logs can be used to determine the Rt, but they may not contain enough information to accurately determine parameters of invaded zones. The inversion-based interpretation of the WL Array resistivity logs provides a direct way of determining the hydrocarbon-bearing formation model. However, interpretation of WL data may be unstable and provide an incorrect equivalent solution due to a strong non-uniqueness of the inverse problem. To find the true model from an unlimited number of equivalent solutions, we propose a stable method that leads to a gradual increase of the formation model complexity.
The major steps are: Estimation of Rt using deep-reading LWD data inversion.Estimation of Rxo using an Rxo WL log.Estimation of Lxo using WL data inversion.Simultaneous corrections of the final model parameters using WL data inversion.
To establish the effectiveness of our method, we first successfully tested it on 2-D and 3-D benchmark models. To examine the practical validity of the method, we applied it to LWD induction data and the Array Lateral Log WL data acquired in a salt-saturated mud environment in a deviated well located in the South China Sea. Our objective was accurate determination of hydrocarbon saturations. Application of our method allowed us to accurately determine the formation resistivity and translate it directly to accurate Sw estimates. We demonstrate that the suggested method provides a lower Sw saturation than the sole WL data interpretation.
An Improved Approach to Estimating True Reservoir Temperature From Transient Temperature Data
Authors: Roux Brian , Sanyal Subir K. , Brown Susan L. 
Published: December 2007

ABSTRACT
In order to develop good estimates on the heat content of a geothermal reservoir and its formation resistivities, and for various drilling and completion decisions one needs, an accurate estimate of the formation temperature. Previous methods to determine static temperature required long shut in periods. The static temperature obtained using the conventional Horner plots were lower than the true reservoir temperature. A quid and easy method has been developed to calculate static temperature from early shut in data in geothermal wells. This method determines static temperature values which are closer to the true reservoir temperature than those obtained from the conventional Horner plot. Recommendations for recording pertinent data to be used in the analysis of temperature buildup and determining initial reservoir temperatures are provided. Several examples are also given.
Radon Transect Analysis in Geothermal Reservoirs
Authors: Semprini Lewis , Kruger Paul 
Published: December 2007

ABSTRACT
Radon transect experiments have been conducted to study flow and emanation characteristics of geothermal reservoirs. Transect experiments have been carried out at three geothermal reservoirs: 1) The vapor-dominated field at The Geysers, California; 2) the liquid-dominated field at Wairakei, New Zealand; and 3) the liquid-dominated field at Cerro Prieto, Mexico.
The radon transect technique involves an examination of the concentration gradients of radon and other natural components in the geofluid along a line of geothermal wells having structural significance in the reservoir. To obtain information on the flow regime in the reservoir, stable gas components in the geothermal fluid are measured in addition to radon. If the transport time of the fluid from the radon source to the wellhead is within a range comensurate with the 3.83-day half life of radon, variations in radon concentration along the transect relative to stable component concentrations provide temporal information on the flow regime.
Data from the transect experiments are being evaluated with mass transport models for vapor and liquid-dominated reservoirs. Results from The Geysers transect experiments show correlation between radon and stable gas components concentration gradients along structural features, indicating physical processes other than radioactive decay are governing radon concentration at the wellhead. Transect tests in the liquid-dominated reservoirs show correlation between radon concentration and fluid enthalpy, indicating the influence of two phase flow conditions in the reservoir. These initial results suggest that radon transect analysis may be useful in studying geothermal reservoirs. They should also help in the selection of wells for pressure transient and mass transient analysis, since it appears that wells in different areas of a large geothermal reservoir may be operating under different thermodynamic conditions.
The Role of Acidic, High Molecular Weight Crude Components in Enhanced Oil Recovery
Authors: Pasquarelli Carl H. , Brauer Paul R. , Wasan Darsh T. , Ciempil Michael , Perl Jeffery P. 
Published: December 2007

ABSTRACT
Acidic resins naturally occurring in crude have been found to be responsible for a variety of interfacial phenomena in oil-aqueous systems. Those components which colloidally suspend high molecular weight asphaltene particles may also be used in enhanced recovery processes to inhibit asphaltene deposition in porous media. This paper presents results of laboratory core flooding tests using a microwave absorption technique to monitor in-situ oil/water saturations during enhanced recovery by alkaline flooding.
Resinous additives were found to significantly alter permeability reductions caused by asphaltene deposition and to affect the formation of a single and continuous oil bank during the laboratory core flood. Data were also obtained for the dynamic interfacial tension, electrophoretic mobility and emulsion stability for the whole crude/aqueous solution with and without the resinous additives.
These observations, combined with microwave analysis are used to suggest a possible mechanism for improved oil recovery through the prevention of asphaltene deposition and resulting permeability reductions.
Field Evaluation of Solids Control Equipment
Authors: Planck Jeffery W. 
Published: December 2007

ABSTRACT
Programs for field evaluation of solids control equipment have been developed for a hand-held programmable calculator. The evaluation yields significant information using typical field equipment.
Such an analysis is useful for economic decisions at the wellsite, regarding a water-based drilling fluid, when equipment efficiency is a consideration. Such economic considerations as barite loss, expensive fluid phase loss, and actual cleaning efficiency of equipment (to determine if adjustments are needed) can be done in the field. The program is easily adjusted for brine systems and can be designed for a specific fluid on a specific well. Examples are included herein, as well as the formulas used (for a fresh water system) and wellsite testing procedures.
Program input data reflect density, rate, and component percentage. The output data yields total solids removed (in pounds per hour), average specific gravity of the solids, the percent and amount (in pounds per hour) of high and low gravity solids, and the amount of fluid lost (in barrels per hour).
An Engineering Economic Model for Thermal Recovery Methods
Authors: Williams R. L. , Ramey H. J. , Brown S. C. , Sanyal S. K. , Raghavan R. 
Published: December 2007

ABSTRACT
An economic model for thermal recovery has been developed. This paper evaluates the optimum recovery rates and production schedule under both steam drive and in-situ combustion processes, possible future production, and the economics of each method based on today's prices.
The recovery model for steam injection is based on the work of Ramey and Raghavan1 which presented a computer program to determine surface steam line and wellbore heat losses, vertical heat losses to the adjacent formation, an oil recovery schedule, and associated steam injection calculations. The recovery model of in-situ combustion is based on the Gates and Ramey2 method of making engineering calculations of air-oil ratios and oil rates as a function of oil recovery.
Once recovery rates for steam drive and in-situ combustion are obtained, a cash flow analysis may be made. Capitalization and operating costs are considered and income is discounted to net present worth. Thus, an engineer may be able to use this method to help evaluate which processes would be more profitable for a particular reservoir.