bluuebunny/crossref_metadata_2025_split huggingface dataset:
Will the Blossom of Unconventional Natural Gas Development in North America Be Repeated in China?
Authors: Xiong Hongjie , Holditch Stephen A. 
Published: December 2007

Abstract
There are substantial volumes of unconventional gas resources in China, including tight gas sands and coal bed methane (CBM). Rapid economic growth in China has increased the demand for more sources of clean energy, such as natural gas from unconventional reservoirs.
In the 1980's in North America, the combination of federal tax credits and various technical development programs sponsored by private organizations, public companies and government agencies fostered the development of technology for unconventional natural gas exploration and exploitation. As those technologies in geology, geophysics, drilling, completion, and production have matured, and the price for natural has increased, the development of unconventional natural gas has been blossoming for last decade globally.
Without question, it is certain that the development of unconventional natural gas in China will be blossoming in the coming decades. However, there are significant challenges and hurdles to overcome before that happens.
This paper first analyzes the conditions and environment required to ensure the development of unconventional natural gas sources, including price, the service industry, cost, and the operational environment. We focus on key technologies in geology, geophysics, and engineering, and how they are tied to the success of unconventional natural gas development. The paper also discusses the advantages China offers, and the challenges in China that must be over come to be sure the blossom of the unconventional natural gas development actually occurs.
On the basis of the author's operational experience both in China and North America, we will discuss the impact of different operational environments on unconventional gas development.
The paper also discusses:
The impact of new technology on unconventional natural gas development; The technologies available and unavailable in China for unconventional natural gas development, and how to use and develop those technologies; and The role of foreign operators in developing unconventional natural gas reservoirs in China.
The paper concludes that an open, competitive, and mature service sector is critical to the future blossom, and that proper government regulations and policies in pricing and taxes, and downstream infrastructure will impact the development of unconventional natural gas resources.
Single-Trip, Multiple-Zone Frac Packing Offshore Sand Control: Overview of 58 Case Histories
Authors: Liu Liangyue , Deng Jianming , Ma Yingwen , Chong King Kwee , Kee Yong Wah 
Published: December 2007

Abstract
Industry experience has shown that frac pack completions can provide effective production stimulation and reliable sand control for unconsolidated sand reservoirs. One of the more rewarding areas of opportunity is in the completion of longer and more complex intervals that can be stimulated with a single frac pack, high-rate water-pack (HRWP) or EX-Tension PacSM Service treatment. One of the major considerations in planning the \well completions in the BZ-25-1 field was design efficiency. To complete each individually zone independently with a Stack Pack completion would have been very time consuming.
This paper presents the results from installing frac-pack and HRWP treatments through a single-trip, multiple-zone (STMZ) completion system in the offshore Bohai field in China. Using the 9 5/8 × 4.75-in. ID single-trip gravel pack tools, operators have performed frac packing and HRWP treatments on 58 wells, on three platforms, during 2003 and 2005 with an average of 3 to 5 zones per well, spending an average of less than 3 days to complete each well.
This paper presents the selection process for the completion technique used to achieve high production efficiency and initial performance of the field. It provides guidelines and results associated with frac packing and demonstrates the importance of selecting completion techniques that will provide high-efficiency production.
Laboratory and Simulation Investigation of Sulfur Deposition in Sour Gas Reservoir
Authors: Xiao Guo , Zhimin Du , Yong Zhang , Li Wang 
Published: December 2007

Abstract
Sulfur deposition in the formation, induced by a reduction in the solubility of the sulfur in the gas phase, may significantly reduce the inflow performance of sour gas wells and even wells have become completely plugged with sulfur in sour gas reservoir within several months. Accurate prediction and effective management of the sulfur deposition are crucial to the economic viability of sour gas reservoirs.
In this paper, the influences of gas flow rate, initial hydrogen sulfide concentration and reservoir rock permeability on sulfur deposition in the core samples from X sour gas reservoir are investigated from a laboratory and simulation perspective. Displacement experiments were conducted using the gas sample with hydrogen sulfide concentration of 19 %. The gas sample were flooded through the actual carbonate core sample of permeability in the range of 0.85 to 20 millidarcy and under different flow rates of 0.82, 1.25 and 3.50 cc/min. In-situ sulfur deposited was measured using Scanning Electron Microscope (SEM) to provide the amount of sulfur deposited along the core samples. In addition, a three-dimensional, multi-component model was developed to evaluate the influences of gas flow rate, initial hydrogen sulfide concentration and reservoir rock permeability on sulfur deposition.
The results indicated that the higher of gas flow rate can reduce the deposition of sulfur, while the higher of hydrogen sulfide concentration have a severe effect on sulfur deposition in sour gas reservoir. In addition, the depositional rate is accelerated rapidly as the rock permeability decreases. This work can help predict exactly the permeability damage rate as a function of flow rate, or initial rock permeability and production performance during the development of sour gas reservoir.
A Critical Evaluation of Sand-Control Completions in the Duri Steamflood, Sumatra, Indonesia
Authors: Underdown David , Chan Henky 
Published: December 2007

Abstract
The Duri field in Sumatra, Indonesia shown in Figure 1 operated by Chevron Pacific Indonesia (CPI) is one of the largest steam flood operations in the world. Producing heavy oil (API gravity ≈ 25) from an essentially unconsolidated reservoir with a depth that ranges from 300 – 700 feet using steam injection @ 300 – 400 °F poses a unique challenge in designing an effective yet economic completion. One of the biggest problems associated with the production of the crude oil in this environment is the production of solids, i.e., sand. It is reported that greater than 1,000,000 lbs of sand per day are produced from the field. In addition to the cost of the re-completions, problems associated with disposing of this amount of sand; and the effect the produced solids have on the facilities such as stabilization of emulsions is a large cost to operations.
A program was initiated in 2002 to evaluate the effectiveness of the completions in the Duri field. This effort involved evaluated field data such as the frequency and type of workovers, the amount and size of produced solids, the nature and number of failed liners, and the frequency of stuck pumps to better understand the efficiency of the sand control completions. Local sand control gravel used in the completions was evaluated for steam dissolution and adherence to API gravel pack sand standards. An audit of the primary sand control screen manufacturer was also conducted to evaluate the quality of the sand control screens used in the completions. In addition, on-site inspections of the operational aspects of the completions were done. The results of the program showed the completion designs, and sand control screens were up to industry standards. However, several operational aspects were identified as opportunities for improvement. The results of the program are presented, and items for improvement of the completion for thermal wells in the Duri field are discussed in this paper.
Development of Small-Size Heavy-Oil Field with Innovative Technology
Authors: Tewari Raj Deo , Malik Mirghani , Idris Mohamed Ahmed Hassan , Naganathan Sivaraman , Pleshkov Dmitry 
Published: December 2007

Abstract
Exploration and development of Heavy oil fields in Muglad Basin in Northern Africa started with conventional vertical wells and as time progressed this matured into drilling of horizontal and high angle wells.
Typically drilling challenges in this area include drilling of very reactive shale's, shallow kick off depths and high build rates. Unconsolidated sandstones and interbedded shale's are sensitive to mud weight and are prone to lost circulation.
First few horizontal wells were drilled with traditional technology of positive displacement motor with Silicate mud. Many of these wells faced hole cleaning challenges leading to pack off -excessive back reaming and stuck pipe incidences, uneven build rates via sliding in interbedded formation leading to high borehole tortuosity. It is significant to note that due to these difficulties one of the planned horizontal wells was sidetracked thrice after stuck pipe incidences and finally completed as a 30 deg deviated well with an AFE over run of 300%.
Taking leaf from experience of horizontal drilling in Muglad basin, rotary steerable system (RSS) has been deployed to drill horizontal well in Umm Bareira field. This field is shallow, highly unconsolidated and heavy oil with viscosity nearly 350 cp. This methodology of drilling has resulted into significant improvement in drilling performance, saving days and cost and eliminating stuck pipe incidences. Well has been completed openhole with sand control strategy using standalone screen with two swell packers for addressing the future reservoir management requirements like intervention for isolating the high water cut intervals in the horizontal section and better productivity and avoiding life cycle risks. Well produced 1300 bopd which is 5 times higher than vertical well and more so make production significant from the field. This paper highlights the learning curve of horizontal well drilling, completion and production of viscous oil field in Muglad basin.
In-Situ Acid System To Clean Up Drill-in Fluid Damage in High-Temperature Gas Wells
Authors: Al-Otaibi M. B. , Al-Moajil A. M. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
Many carbonate and sandstone formations are completed with horizontal and extended reach wellbores. Drill-in fluids are generally water-based muds containing a viscosifier, a fluid-loss reducer, sized salts or and calcium carbonate particles. Filter cake is a major cause of restricted flow from the target zone. Effective filter cake removal during well completion is very difficult to achieve, especially in deep heterogeneous reservoirs. The obstacles encountered are the difficulty of zonal coverage of cleaning fluids with the filter cake throughout the whole interval, and controlling the rate of removal of the filter cake to ensure uniform coverage of the whole interval. The cleaning solutions can be acids, enzymes, oxidizers, chelating agents, or combinations of these materials. Enzymes are only specific for biopolymers and will not attack the calcium carbonate particles. Acids are highly reactive and corrosive fluids.
A new in-situ acid system can deliver the acid to long interval wells. The treatment fluid contains an acid precursor that provides time-controlled downhole acid release. Several lab experiments were conducted to examine thermal stability of fluids at high temperatures. The kinetics of acid producing reactions were examined in detail. Modified dynamic and static HPHT fluid loss cells were used to assess the effectiveness of the system in cleaning drill-in fluid filter cake. The surface tension of the acid precursor and the spent acid was measured as a function of temperature and acid concentration.
No phase separation of precipitation was noted when the precursor solution what heated to 250F for 24 hours. Unlike conventional HCl acid-based systems, the slow reaction kinetics ensures better distribution of the new fluid across long sections with minimal losses during pumping. The HPHT experiments showed a significant improvement in the efficiency of removing acid soluble portions of the filter cake. Surface tension measurements indicated that the spent acid solution had low surface tension, which will accelerate lifting the spent acid from tight formations.
Successful Application of a Novel Fracturing Fluid in the Chicontepec Basin, Mexico
Authors: Centurion S. , Rengifo M. , Cortona M. , Padilla F. , Lavalle A. 
Published: December 2007

Abstract
For several decades, the most commonly used hydraulic fracturing fluids have been water based, and used a variety of different polymers. The effects of such fluids on formations, and even on the frac pack as such, have constituted the basis for several papers and discussions. Several of these discussions were focused mainly on the efforts devoted to the optimization of the interaction between the frac fluid and the formation. Among others, the probable polymer damage brought about by the frac fluid is one of the most frequently discussed topics.
Undoubtedly, the use of a polymer-free frac fluid, surfactant based with viscous-elastic (VES) properties, has been one of the most attractive topics for Pemex E&P within its application program of new technologies.
The present document includes a detailed explanation of the properties of this fluid, including the description of its mechanism for the generation of viscous-elastic properties and the breakage thereof, as well as its general chemistry.
In addition, the application of these kinds of fluids had been contemplated within PEMEX E&P´s plans, to be used in Chicontepec basin.
This formation is regarded as heterogeneous and highly complex. The only way to produce the wells at economically acceptable levels is through the technique of hydraulic fracturing.
The first work done with this technology was carried out during 2005, and it was deemed a success by the producing company. The description of the well, in which the fluid was used, together with all of the relevant information thereof, has been included in the present document. An assessment of the early production and well response was carried out through a nodal analysis and a simulator of the responses related to production rates, both linked to a fracturing simulator. These too will be discussed in this paper.
Borehole Instability Analysis in an Anisotropic and Heterogeneous Shale Formation
Authors: Yamamoto K. , Tamura Mitsuo , Mizuho N. Goto 
Published: December 2007

Abstract
In an oil field, drilling engineers had encountered numerous drilling troubles such as sloughing and stuck pipe problems across a shale interval overlaying the reservoir. In a preliminary study the authors carried out, the instability phenomena contradicted to the simple theory of homogeneous material. For example, hole condit ion worsened in the highly deviated well although the stress regime is strike-slip fault type.
The study aims to find out the root cause of such complex instability phenomena, to developnu merical method that can be used for mud weight optimization, and to establish the drilling guideline to mitigate the troubles
Using the 3D poroelastic and laminated fo rmation model, we found that wellbore condition can be worsened as hole inclination increase even in the strike-slip stress condition. In such case, higher mud weight cause wider failure a readue to the fluid pressure penetration into weak planes of the laminated shale formation.
The paper shows that the appropriate numerical method with three-dimensional poroe lastic model with heterogeneous the strength and permeability can predict such unconventional wellbore instability phenomena.
Best Practice and Case Study of Interwell Tracer Program Designs
Authors: Cubillos H. , Torgersen H. , Chatzichristos C. , Lamela M. 
Published: December 2007

Abstract
It is well known in the petroleum industry that tracer data can provide valuable information on reservoir characteristics and fluid flow performance. However, a prerequisite for obtaining reliable information is careful planning, design, and field implementation.
The application of gas tracer technology for improving the reservoir description and optimizing the RKF Field miscible gas injection project was presented earlier. The current paper compliments the earlier work by discussing issues related to design and field implementation of the tracer program, including definition of the objectives, determination of tracer types and amounts, and evaluation of sampling and detection techniques.
In this paper we document the lessons learned and propose best practices based on our experience with tracers in the RKF Field, Algeria. A critical element is integration of the field operator and Research Centre personnel with the subsurface team during all phases of the tracer program. This integration has been very important in obtaining good quality data in the RKF project.
We also review common mistakes and bad practices that could occur in the absence of a robust tracer design program. The importance of analytical calculations, simulation, sampling frequency and the recycling of tracers are also among the design topics that are addressed.
The proposed best practices can be applied by field operators in the design of future tracer projects and can also be used to identify the causes of tracer monitoring problems in existing projects. We hope that this paper will be of use to those managing or planning tracer projects.
Rapid Planning and Execution of the First Multilateral Well in the Gulf of Thailand: Results and Lessons Learned
Authors: Upchurch Eric R. , Dooley Paul A. , Hall Kenneth H. , Laohaburanakit Songklod , Maroongroge Vichai , McKee L. Douglas , Nucharoen Panaratn , Wagner Michael R. 
Published: December 2007

AbstractIn early 2006 Chevron International E&P drilled and completed the first multilateral well in the Gulf of Thailand. Routine development drilling in the Kaphong Field of the Pattani Basin unexpectedly discovered two production horizons that possessed reservoir characteristics and sufficient oil reserves to make each a viable horizontal well candidate. At the time, however, only a single drilling slot was available on the platform; thus, dictating that only one well bore could be drilled to tap both reservoirs. Further complicating the problem was the fact that the drilling rig which discovered the horizons would be moving to a new platform a short 5 weeks after it was understood by reservoir engineers, geologists and geophysicists that multiple horizontal well candidates existed.This paper chronicles the rapid processes that took place to evaluate, plan and execute the first multilateral well in the Gulf of Thailand. More importantly, though, this paper captures the unintended consequences (both good and bad) that came with executing this project so quickly. This includes an analysis of how decision making, project planning and ultimate execution where affected by the short time window available. From this we discuss lessons learned that may be universally applicable when rapidly expanding the use of technology in a remote region of the world (regardless of how small that expansion is).
Innovative Technology/Best Practices Maximizes ROP, Saving the Operator $U.S.1.5 Million in Chicontepec Project, Mexico
Authors: Quiroga J. , Valera R. , Fernandez A. , Arias A. , Bravo H. 
Published: December 2007

Abstract
Chicontepec field is located in the northern portion of the state of Veracruz, Mexico. The typical well drilled in the field has a directional "S" shape profile (up to 4°/30m DLS) with three casing points. The main challenge is constructing the 6-3/4" section generally between 500m to 2000m including Tantoyuca (500-700m), Guayabal (700-1200m), and Chicontepec Formations (1200-2000m). The Tantoyuca formation is a shaley sandstone with an average UCS of 8,000psi. The Guayabal is deep-water shale with an average UCS of 3,000psi. Finally, the Chicontepec paleochannel is composed of sandstone and shale with an average UCS of 10,000psi with maximum values reaching 25,000 psi.
A detailed analysis of the application was performed to optimize the BHA (motor/PDC bit) to improve performance and drill the section in one fast run. As a result of the study, the operator elected to implement a two-staged performance improvement strategy including a more powerful mud motor (5:6 greater torque) in combination with a 5-bladed PDC with 13mm cutters.
The new bit design selected has an innovative depth-of-cut control technology designed to eliminate the reactive torque problem while sliding. The bit also has a new, highly abrasive resistant PDC cutter for increased durability. This new technology was coupled with a revised set of operating parameters and drilling recommendations to optimize performance and meet the operator's ROP requirements.
The authors will document how the implementation of best practices and the correct combination of the motor/PDC BHA contributed to drill 30% of all 6-3/4" production sections in 2005 at over 33m/hr average ROP. This resulted in an average reduction of three days to finish the wells, saving the operator $1.5 Million USD while setting a new field benchmark.
Improving Performance of the Naturally Fractured Carbonate Reservoirs by Means of Various Stimulation and Completion Techniques
Authors: Jahediesfanjani H. , Civan F. 
Published: December 2007

AbstractThis study presents a parametric study to evaluate the performance of the vertical and horizontal wellbores with and without fractures and frac-and-packs, and multi-lateral horizontal wells with various laterals and branches for different carbonate reservoir characteristics. Series of three phase and three dimensional mathematical models are prepared to simulate the naturally fractured carbonate reservoir performance under various scenarios. A novel approach is utilized to effectively simulate the performance of the hydraulic fractures by considering the induced fractures as a boundary condition for the reservoir system.Potential stimulation and completion techniques are compared by three measures: Effective normalized cumulative hydrocarbon production, volume fraction of the influenced reservoir domain, and normalized damage ratio. Performance and economical analyses are carried out, indicating that the completion methods covering more reservoir volume and effectively connecting the natural fractures to the wellbore yield a higher efficiency. It is demonstrated that the effectiveness of all the stimulation techniques strongly depends on the angle by which the natural fractures are intersected throughout the reservoir, and the normalized damage ratio caused by the completion and stimulation technique. The economical analysis and evaluation help determine the best completion and stimulation technique.