bluuebunny/crossref_metadata_2025 huggingface dataset:
Numerical Analysis of Radial Flow in a Natural Fracture: Applications in Drilling Performance and Reservoir Characterization
Authors: Lavrov Alexandre , Tronvoll Johan
Published: December 2007

A theoretical framework is developed for radial flow of a Newtonian fluid from a single, arbitrarily inclined fracture into a borehole, as it is the case during formation fluid influx in underbalance drilling, or during oil production in naturally-fractured reservoirs. The model should be equally well applicable for the simulation of fluid flow from a borehole into a fracture, as it is the case during mudloss events in overbalance drilling.

The fracture is assumed to be rectangular in shape and to obey an empirical exponential deformation law, i.e. hydraulic aperture in function of effective stress.

A parametric study is carried out in order to investigate the effect of fracture inclination, fracture dimensions, fracture compressibility, and borehole position, on the flow rate dynamics. The largest in-plane size of the fracture has very little effect on the flow rate at the initial stage of the flow. It does not affect the initial peak in the flow rate versus time curve. It affects, however, substantially the flow rate at later stages, and also the total amount of produced (or lost) fluid. The smallest in-plane size of the fracture considerably affects the initial part of the curve. It also affects the total amount of produced /lost fluid. The initial peak in the flow rate is lower and the duration of the discharge is longer in case of a borehole located at the periphery of the fracture in comparison to the one located in the central part of the same fracture. This holds for different types of fracture orientation and geometry, i.e. horizontal and vertical, isometric and elongated fractures. An increase in the fracture's normal compressibility only slightly affects the height of the initial peak in the fluid flow versus time curve, but has a large effect on the tail of the curve. Higher compressibility also leads to that the cumulative amount of produced /lost fluid is higher.

The results also show that the proposed model may be useful in estimating hydrocarbon reserves in place based on drilling data as well as for estimating potential production profiles and recovery factor.
Application of New Technology in the Completion of ERD Wells, Sakhalin-1 Development
Authors: Helmy M. W. , Veselka A. , Benish T. , Yeh C. , Asmann M. , Yeager D. , Martin B. , Barry M.
Published: December 2007

This paper presents methods for the completion and evaluation of extended-reach-drilling (ERD) wells with greater than 10,000 m measured depth and horizontal completion intervals surpassing 3000 m for the Chayvo Field in the Sakhalin-1 development in Russia. The objectives of the completion strategy are a) maintain a uniform production profile along the wellbore by reducing flow from high permeability zones b) mitigate the potential for sand production and c) maintain zonal isolation between various reservoir facies. A combination of external isolation packers, inflow control nozzles, sand screens, and pre-drilled liner were used. The inflow control nozzles were sized to restrict flow from high permeability zones and maintain a more uniform production profile along the wellbore. Other issues that influenced the final completion design include rock strength, sand particle size, and reservoir deliverability. The design, sizing and placement of the inflow control nozzles, screens, and isolation packers are discussed in detail.

Evaluating the performance of the completion presents unique challenges. A series of production logging and pressure tests were run to reduce uncertainties associated with the estimation of reservoir properties and completion efficiency. These uncertainties were introduced by the presence of the inflow control nozzles and the multi-layer nature of the reservoir. The pressure buildup and production logging data were integrated, and the analysis used to evaluate the effectiveness of the completion technique.
How Minimum Interval Concept Can Improve Bit Performance Evaluation
Authors: Macini P. , Magagni M. , Da Dalt G. , Valente P.
Published: December 2007

The paper analyzes a novel operative procedure of geological and geomechanical subdivisions of the formations, called Minimum Interval (MI). The MI concept, used in combination with other evaluation indexes, can improve consistently the evaluation of bit performances. This research compares three indexes for bit performance evaluation, i.e., cost-per-meter (CM), Specific Energy (SE) and Bit Index (BI), applied to a new type of drilling-bit database, named Formation Drillability Catalog (FDC), organized in order to implement the MI concept. Basically, the FDC is a novel classification of drilled formations conceived and prepared at Eni E&P Division (Italy), aimed to the geomechanical characterization by means of a large number of significant geological and drilling parameters, each one referred to single MI’s. So far, five wells have been identified and tested for bit performance evaluation. The FDC turned out to be functional to BI, since it discloses and organizes lithostratigraphical characters that are not easily detectable or usable from bit records or master logs, allowing for targeted bit performance evaluations. Results of this case study showed that the cross correlation between BI, CM and SE can help to identify the best performer bit for each formation and for each borehole section. The quality of bit performance analyses obtained with BI and SE (through the MI concept) seems more effective than those based on CM, performed on bit records, and can also be used as a valuable tool for drill-bit selection.
Use of Extremely High Time-Resolution Production Data To Characterize Hydraulic Fracture Properties
Authors: Crafton J. W. , Gunderson D.
Published: December 2007

By employing flowback surface rate and pressure data recorded at very high frequency immediately following hydraulic fracture stimulation shutdown, it is possible to obtain estimates of fracture conductivity, fracture length and near-wellbore matrix permeability, as well as confirmation of closure pressure. Because the wellbore and induced hydraulic fracture are liquid filled at very early time, it is possible to observe meaningful signatures in the flowback production data when it is recorded with sufficiently high time resolution, on the order of 20 or more observations per minute. Dissipation of the super-charge is detectable, and the highly elliptical flow dominated by the fracture is clearly evident.

Recognition of these flow regimes makes interpretation of fracture conductivity, effective length and an upper limit estimate of matrix permeability possible. Examples of actual field results are shown in the paper. When compared with published proppant bed conductivities for the expected stress loading, excellent correlation is obtained. The computed effective fracture lengths are somewhat shorter than that expected based on the design. In all cases, the near-fracture matrix permeabilities are higher than observed in later time production histories.
Production Sharing Agreements—An Initiative to Reform
Authors: Wadood S.
Published: December 2007

Production Sharing agreements are the predominant type of contractual arrangement, governing the relation between governments and foreign oil companies throughout the exploration and development phase. PSA were first introduced in Indonesia in 1966 and since then varied in some elements but witnessed no major development.

The paper/presentation will argue that in the current context of sustained oil prices, need of increasing production, depletion of reservoirs, and the remaining reserves, Governments and Foreign Oil companies need to revisit some of the basic elements of the PSAs in order to address the above context adequately.

The rigidness of the current structure of PSA does not allow government and E&P companies to adapt their strategies throughout the development phase. To overcome some of the disadvantages of PSAs, governments can introduce dynamic variables such as: Dynamic profit share linked to Crude prices.Flexible Cost Recovery systemsIncentive system based on key performance indicators
Application of new materials and parts for ESP units running in wells of abnormal operating conditions
Authors: Grebenyuk Alexander N.
Published: December 2007

Analysis of OAO "NNP" wells for 2004 showed that total number of premature failures made 618 and compised 167caused by cable faults, 371 caused by ESP faults, 43 through fault of downhole pump and hydraulic protection, and 37 due to tubing failures.

The main part of failures falls to ESP units. That is why quality of materials used in ESP operating parts should be of top priority. The main causes of ESP failures across OAO "NNP" are the following: aggressive environment (corrosion) – 13%, mechanical impurities – 43%, scales – 25%, proppant washout – 11%, tubing leaks – 11%, poor inflow – 1%.

The main factors aggravating the ESP work are salt deposits on the operating parts and their corrosion. Salt deposits and corrosion result in flow characteristics deterioration, vibration amplification, what consequentially shortens failure free operation time of ESP units. The average failure free operation time of these wells made 95 days due to scales and 103 days due to corrosion.

Salt deposit and corrosion causes

High watercut level (exceeding 80%) significantly intensifies the aggressive environment impact and corrosion process.

Having analyzed composition of salts and deposit formation process we can specify 3 root causes of salt deposits in ESP parts.

The first one is based on the definite reservoir fluid properties – watercut level exceeding 80%, presence of dissolved and undissolved minerals as wells as aggressive environment.

The second cause is of operational nature and may be entailed by: change of thermobaric conditions in a well or in ESP, leading to precipitation of some compounds of the first group. So, shift of the work zone to the left side of the flow dynamic properties (i.e. when the pump is forced to decrease the flow rate) leads to rising of the flowing fluid temperature and enhancement of cavitation processes, what subsequently leads to precipitation of CaCO3 (calcium carbonate), in particular;Mixing of formation fluid with injected water of different composition in the process of water injection for formation pressure maintenance may result in creation of salt-forming compounds and aggressive environment.

The third cause is design of ESP which may lead to: formation of vortex and stall zones;corrosion of working parts surfaces which leads to damage of smooth surfaces where salt deposits can easily form then;Besides, salt deposits may be resulted from influence of electrostatic forces (initiation of galvanic couples).
Applications of Artificial Neural Networks and Dipole Sonic Anisotropy in Low-Porosity, Naturally Fractured, Complex Lithology Formations in the Southern Land Region of México
Authors: Bueno E. O. J. , Pérez I. C. , Escamilla G. , Mesa H. , Ponce B. , Graham R. , Kessler C. , Murillo J.
Published: December 2007

The Antonio J. Bermudez basin in Southern Mexico is a low porosity massive Jurassic and Cretaceous carbonate reservoir that is extensively faulted and fractured due to post depositional salt intrusions. The natural fractures create many drilling challenges and obstacles. Underbalanced drilling with foam fluid systems has been used to minimize mud losses in these fracture systems. The underbalance drilling, and drilling with casing greatly improves well construction, but these drilling techniques also create many formation evaluation challenges. For example, open hole sonic logs require a liquid filled borehole. Also, formation resistivity is such that lateral logs would be the preferred resistivity device, but they require a conductive borehole fluid.

Artificial Neural Network (ANN) methods have traditionally been used for reconstruction of petrophysical data due to tool pulls and poor borehole conditions. Drilling obstacles, in this field, sometimes prohibit the running of conventional open hole logs. Thus, an ANN technique has been developed that uses cased hole pulsed neutron log (PNL) data to synthetically generate a conventional, open hole, triple combo log. These logs are used for well-to-well correlations and for petrophysical evaluation. Still, due to the synthetic smoothing of an ANN result based on casing formation evaluation data (i.e., PNL), detection of natural fractures remains problematic using ANN-based synthetic density data. On the other hand, cased hole dipole sonic anisotropy analysis is routinely used successfully to identify natural fracture systems and far field stress orientation for geomechanical applications. Intervals to be perforated are selected by combining through-casing sonic information with petrophysical analysis of synthetic open hole logs.

Data and production results from several wells will be presented and discussed in the paper.
A New Model to Describe Particle Movement and Deposition in Porous Media
Authors: Kalantari-Dahaghi A. , Moghadasi J. , Gholami V.
Published: December 2007

Formation damage resulting from invasion of solid suspensions have been studied by several investigators and some modeling approaches have also been reported in the literature, most notably the application of effective medium theory and percolation theory in two and three-dimensional capillary networks.

This paper presents a new model, which is based on mass balance transfer function of particles flowing through the porous media. The linear forms of the model are described as well as the radial forms. Although the differential equations derived are similar to the general form of diffusion-convection equations, the marked difference is the suitability of the model, for being applied for variation of parameters, such as particle concentration in the fluid, injection rate, density of solid particles, against the depth and time of invasion. This transfer function is solved by MATLAB program (Version 5.3.2) and SIMULINK software. The results of the simulation run agree reasonably well with the experimental damage data obtained in laboratory.
Implementation of a Total System Production Optimization Model in a Complex Gas-Lifted Offshore Operation
Authors: Nadar M. S. , Schneider T. S. , Jackson K. L. , McKie C. J. N. , Hamid J.
Published: December 2007

A total system production optimization model has been implemented in a complex gas-lifted offshore operation, resulting in production gains and operating cost reductions. Whereas previous optimization models considered only the wells and production gathering network, the new model is able to consider the combined performance of the total system, including downhole well configurations, the complex production gathering and lift-gas distribution pipeline networks, separators, compressors and pumps. The model is applicable to most gas-lifted fields, and will be particularly beneficial when applied to those with complex production systems, and where compressors are a constraint on total system performance.

The output from the optimization model principally comprises recommended values for individual well gas lift injection rates, separator pressures, compressor discharge pressures and compressor utilization. Field results are presented in the paper to demonstrate how implementing the optimizer's recommendations in the field resulted in economic benefits through increased production and reduced operating costs. Also described is how the model allows field operations engineers to re-optimize field control parameters on a more frequent basis and with less manpower than previously.

The successful implementation of a complex model with such a broad scope is as dependent upon the implementation process as it is upon the technology. Therefore, in addition to describing the details of the model itself, this paper will cover the issues that arose during the implementation and how they were resolved. These include the level of manpower and support required, project organization and execution, and the processes required to sustain the benefits after the initial optimization gains have been realized.
Research of Surfactants Effect on Methane Hydrate Formation
Authors: Bin Dou , Guosheng Jiang , Xiang Wu , Fenglin Tang
Published: December 2007

This paper deals with the effects of a surfactant additive on the formation of methane hydrate in water system with and without sodium dodecyl sulfate (SDS). The results manifested that the presence of SDS could not only accelerate the hydrate formation process, but also increase the partition coefficient of methane between hydrate and vapor drastically. The paper then describes our experimental observations of the hydrate formation from methane, to show how the hydrate formation behaviors are affected by the additives of chamber partially filled with a quiescent pool of water (pure water or an aqueous SDS solution) to compensate for the gas consumption due to the hydrate formation, thereby maintaining a constant pressure inside the chamber. The results revealed that the addition of SDS not only on the liquid-pool surface but also on the chamber walls above the level of the pool surface, leaving the bulk of the liquid pool free from hydrate crystals. An excessive addition of SDS beyond the solubility was found to cause a decrease in the rate of hydrate formation but an increase in the final level of the water-to-hydrate conversion.
A New Method for Accurate and Practical Upscaling in Highly Heterogeneous Reservoir Models
Authors: Zhang Pinggang , Pickup Gillian , Christie Mike
Published: December 2007

Geologists often generate highly heterogeneous descriptions of reservoirs, containing complex structures which are likely to give rise to very tortuous flow paths. However, these models contain too many grid cells for multiphase flow simulation and the number of cells must be reduced by upscaling for reservoir simulation. Conventional upscaling methods often have difficulty in the representation of tortuous flow paths, mainly due to the inappropriate assumptions concerning the boundary conditions. An accurate and practical upscaling method, which is able to preserve the flow behaviour caused by highly heterogeneous fine scale geological features, is therefore required.

In this paper, the problems encountered in routinely used upscaling approaches are outlined, and a more accurate and practical way of performing upscaling is proposed. The new upscaling method, Well Drive Upscaling (WDU), employs the actual reservoir boundary conditions. The main advantage of this method is that the dominant flow paths can be preserved, and thus the geological knowledge can be assimilated appropriately. The new method has firstly been applied to a synthetic model with a tortuous channel, and is shown to have significant improvement over the traditional approach. The sensitivity study on the scale up factor using a bench mark model shows the advantage of the method with various scale up factors. The method was then applied to a model of a field in the central North Sea, which involves three phase flow. In the cases studied, the WDU method produced a comparable result to the dynamic Pore Volume Weighted approach which involves running the fine grid simulation and computing appropriate relative permeabilities and inter-block transmissibilities. The new method makes the upscaling process both practical and accurate and ensures that field predictions can be made more confidently with greater geological realism.
Will the Blossom of Unconventional Natural Gas Development in North America Be Repeated in China?
Authors: Xiong Hongjie , Holditch Stephen A.
Published: December 2007

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

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

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

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

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

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

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

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

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

In 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

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

This 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.
Determination of Reservoir Inflow With Pulsed Neutron Logs Under Subcriticai Flow Conditions
Authors: Poe B. D. , Butsch R. J.
Published: December 2007

This paper presents some recent developments in a production logging technique that utilizes Pulsed Neutron log measurements for the evaluation of the formation inflow into a wellbore, of which one or more of the completed intervals may be located in the annulus between the casing and tubing strings above the end of the tubing. Of particular importance in this work is the capability of determining the formation inflow profile in the well in cases where the well outflow velocity is less than that required to continuously transport and unload liquids from the well. Sub-critical velocities are commonly encountered in low productivity gas wells that produce liquids, whether they are produced directly from the formation and/or condensed well fluids, water and hydrocarbons.

This paper presents a sub-critical velocity analysis that has been implemented in a Pulsed Neutron production logging technique in order to have the capability to reliably evaluate the formation inflow into wells in which the velocities are so low that no other production logging methodology is possible. Coupled with the numerical modeling of the Pulsed Neutron production log evaluation, test pit measurements of the annular flow water velocities with the Pulsed Neutron logging technique have been reliably and accurately measured to as low as 3 ft/min (0.05 ft/s).
Stability Analysis of Deviated Boreholes Using the Mogi-Coulomb Failure Criterion, With Applications to Some Oil and Gas Reservoirs
Authors: Al-Ajmi A. M. , Zimmerman R. W.
Published: December 2007

Borehole collapse is the commonly encountered wellbore stability problem during drilling. The precursor of such borehole failure can be often eliminated by a proper determination of the critical mud pressure. Recently, Al-Ajmi and Zimmerman developed a new 3D analytical model to estimate the mud pressure required to avoid shear failure (i.e., borehole collapse) at the wall of arbitrary oriented boreholes. This had been achieved by using linear elasticity theory to calculate the stresses around the borehole, in conjunction with the fully-polyaxial Mogi-Coulomb criterion to predict failure. The developed model has been used to study the behaviour of the collapse pressure under different in situ stress regimes. We have found that the optimum drilling trajectory is directly related to the principal in situ stresses. Accordingly, we have developed a new analytical solution to optimize well path. The stability model has been applied to several field cases, and the new model in each case is consistent with the field experience. It has been concluded that the optimum wellbore profile can be ensured by employing the developed analytical stability model.
Simulation of Nitrogen Injection into Naturally Fractured Reservoirs Based on Uncertain Properties and Proper Matrix Grid Resolution
Authors: Vicencio O. A. , Sepehrnoori K.
Published: December 2007

This paper addresses a study of nitrogen injection in naturally fractured reservoirs based on uncertain properties that impact the nitrogen distribution and the oil recovery under gravity drainage mechanism. This research focuses on sensitivity studies based on matrix block sizes and capillary continuity to access their impact on the gravity drainage mechanism. In addition, a study of the matrix grid resolution was performed to investigate the effects of vertical and horizontal subgridding on matrix oil recovery.

This study is a continuation of a research which considered a simulation of nitrogen injection through different scenarios by using the same conceptual model with isotropic and anisotropic matrix blocks, the injection of different gases and the construction of a thermal compositional case study to determine the variations of temperature that mainly occur in the gas cap.

ECLIPSE commercial simulator with compositional formulation and dual porosity option was used for the field simulation case studies. Simulation results considering variations in matrix block sizes with same shape factor indicated that gravity drainage mechanism depends not only on matrix block size but also on reservoir depth and nitrogen arrival time. For all cases studies, highest oil recovery was obtained for slabs with biggest matrix block height.

Furthermore, our sensitivity studies for capillary continuity were performed using several fracture apertures considering block size with 10 ft height. Simulation results indicated that oil recovery is affected by a factor that range from 1 to 2.2 by considering fracture apertures between 10 to 300 microns. Since fracture aperture histogram for the reservoir under study averaged 250 microns; discontinuity capillarity is a good approximation for the reservoir under study. Our simulation results suggest that for a naturally fractured reservoir study is necessary to reduce uncertainty of fracture apertures because it strongly impacts the oil recovery.

Subsequently, we investigate the effects of matrix subgridding in vertical and horizontal directions on total oil production by using a stack conceptual model of two matrix blocks surrounded by fractures. The matrix and fracture systems were divided into a number of Cartesian sub-grids and we used the compositional single porosity model of ECLIPSE 300 to perform our simulation runs.

Simulation results indicated that oil recovery for a grid refinement case study using 3×3×68 gridblocks was higher by a factor of 1.124 than the base case using 3×3×5 gridblocks. In addition, the total oil production for the case using 9×9×68 gridblocks was higher by a factor of 1.09 in comparison with the case using 3×3×5 gridblocks. Based on our simulation results; we concluded that subgridding is specially important when we have gravity drainage as the main oil recovery mechanism.