bluuebunny/crossref_metadata_2025_split huggingface dataset:
Operating Experience of ESP's in South Oman
Authors: Norris Chris , Al-Hinai Saif H. 
Published: December 2007

Abstract
Petroleum Development Oman (PDO) operates some 1000 producing oil wells in the southern part of the country. These wells account for about 350,000 BOPD of the total PDO production of 800,000 BOPD. From being considered an "experimental" mode of artificial lift in 1987, ESP's have assumed such importance that over 40% of current South Oman oil production comes from the 145± wells on ESP lift. New wells and ESP conversions are now proceeding at a rate of 80/year and is expected to increase further.
Well conditions are relatively benign and average run lives of at least two or three years have been achieved. Operational aspects including successful central Supervisory Control and Data Acquisition (SCADA) monitoring and control of the ESP wells have proven to be beneficial. However, some limitations on new well sizing due to initial emulsion problems caused by high viscosity and low water cut production have been encountered. In addition a new contract encompassing design, surveillance, service engineering support and equipment sales has recently been awarded.
This paper discusses formulation and operational experience of this four year contract for South Oman and the benefits realized from the remote monitoring and control aspects.
Characterisation of a Complex Carbonate Reservoir: A Case Study from a Western Offshore Field of India
Authors: Suryanarayana K. , Lahiri G. 
Published: December 2007

ABSTRACT
Bombay High is the largest oil field discovered in India so far. Major hydrocarbon accumulation is in the middle and lower Miocene layered carbonates with shale intercalations. Many wells of the field have become sick due to high water cut, high GOR and rapid pressure decline. To understand the present scenario, reservoir characterization of a selected area was carried out by integrating petrophysical, geological, reservoir and seismic data. From the reinterpretation of the available seismic data, subtle faults could be identified. Detailed facies analysis has been carried out, with the innovative concept of generation of facies ratio maps using core and well log data as inputs. Using statistical multiple regression analysis, core and well log data were combined and a permeability relationship has been derived to generate a permeability log in each well. Permeability was successfully scaled up to the reservoir level by matching the log derived permeability to the well test permeability. Reservoir quality had been estimated combining the permeability data with facies analysis. RFT pressure depletion analysis has been carried out to examine the effectiveness of intervening shales as flow barriers. Resistivity modelling was used to understand the formation true resistivity character and to examine the side bed effects, in this layered sequence.
The identified faults can have considerable impact on the fluid contacts. Facies analysis has given proper insight into the depositional environment. Permeability estimation has led to better visualisation of the fluid flow behavior both laterally and vertically across the study area. RFT pressure data analysis, along with the facies analysis could identify the hydraulic sealing character of various shale layers. Resistivity modelling showed that a significant increase in the net hydrocarbon pore volume can be achieved by carrying out judicious corrections on the measured resistivity, especially with the induction type measurements.
Generation of detailed facies ratio maps, study of spatial variations in permeability, usage of resistivity modelling for understanding the formation true resistivity character and such other discussed techniques can be applied to charecterise similar complex carbonate reservoirs.
Proven Technology Yields High Impact Results - A Case History of Water Shut-Off in the PNZVs South Umm Gudair Field
Authors: Johnson R.S. , Khater M.R. , Razzaque S.A. , Al-Fozan M.S. , Al-Mutairi T.Z. , Qidwai M.M. 
Published: December 2007

Proven Technology Yields High Impact Results - A Case History of Water Shut-Off in the PNZVs South Umm Gudair Field.

Summary
The South Umm Gudair (SUG) Field is a large, anticlinal, primarily edge water drive reservoir located in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia. A successful water shut-off program was implemented in SUG's Ratawi Oolite reservoir during 1994/95. This program relied on zonal isolation tests, spinner surveys, thermal decay logs, and correlations with surrounding wells to identify watered-out intervals. Since the field produces using electric submersible pumps (ESP's), surveys were run through a downhole bypass tool. A comparison was made between thermal decay logs run under static and dynamic conditions in an analogous reservoir to evaluate invasion by kill fluids. Remedial action including cement plugbacks, reperforations, additional perforations, and acidizations were implemented based on the interpretations. The techniques presented in this paper are applicable to reservoirs requiring water shut-off analysis.

Introduction
The SUG field was discovered in 1966. The field produces from the Ratawi Oolite reservoir of Lower Cretaceous age. The reservoir straddles the boundary line between the PNZ and Kuwait. It Is operated by Joint Operations In the PNZ and by KOC in Kuwait. Joint Operations is an organization comprised of personnel from Saudi Arabian Texaco and Kuwait Oil Company.
When the water shut-off program was initiated in July 1994, there were 17 producing wells located on 320-acre spacing. Field development coincided with the workover program. An additional twelve infill wells were drilled in SUG, with the first well activated in November 1994. Figure 1 provides a structure map and well locations. The production history for the entire field is shown in Figure 2. Although this paper will focus on the workover results, production from the infill drilling program is included in the graph.
Approximately nine workovers for water shut-off were performed prior to 1994; the last of which occurred in 1987. Prior to the workover program, oil production averaged 31,000 BOPD and was declining at 3%/yr. The water cut had gradually increased to 48%. Cumulative production through December 1995 was 420 MMBBLS.
Thirteen wells were worked over during the 1994/95 program. Figure 3 shows that the workovers doubled oil production in these wells from 20,000 BOPD to 40,000 BOPD and decreased water production by more than 50%.

Reservoir and Fluid Properties
The average depth of the producing horizon is -8200' SS or 8825' TVD. The original oil-water-contact (OWC) is -8450' SS. The reservoir is 200' - 300' thick and consists of wackestones and packstones. P. 406
Energy Taxes Policies and Market Shares for Oil and Gas
Authors: Pona Afonso de Paiva , da Costa Jose Escada 
Published: December 2007

Abstract
Totally unregulated economy would tell us that the price for any good, natural gas in the Portuguese market included, is established by the intersection of demand and supply curves.
This is however valid in a fully open market place through the bargaining of many buyers and sellers, and certainly not the case for Portugal and other countries with small economic weight and even more if they are not producers. In such case sale prices are established almost independently of local demand and supply conditions and market mechanisms are not expected to insure a correct gas industry implementation.
Present work tries to propose a method to forecast gas consumption's in Portugal, for different gas prices, considering state intervention, either by energy taxation or subsidize policies.
Compositional Modeling of Two-Phase Hydrocarbon Reservoirs
Authors: Hamoodi A. N. , Abed A. F. , Firoozabadi A. 
Published: December 2007

Abstract
Compositional modeling of saturated two-phase hydrocarbon reservoirs is a difficult task. When both oil and gas phases are present, the characterization of one may not be the same as the other. Proper characterization will, therefore, become an issue.
In this paper, we examine the compositional data of four two-phase hydrocarbon reservoirs. An attempt is made to characterize the reservoir fluids in both the gas-cap and the oil-column. In addition to the characterization of the plus fractions, we also review reservoir fluid sampling and validation, and theoretical and practical aspects of compositional modeling.
Resolving Wettability in a Giant Carbonate Reservoir
Authors: Webb K. J , Black C. J. J. , Namba T. 
Published: December 2007

Abstract
During a laboratory waterflood study, undertaken at reservoir conditions to provide representative displacement data for predictive reservoir simulation studies, an investigation into acquiring representative wettability showed preserved samples exhibited significantly more oil wet character than restored samples. Further investigations concluded that core retrieval and/dr storage resulted in increased oil wet character. Preserved state samples were not therefore representative.
NE Abu Dhabi – New Evidences of Wrench Tectonics Associated with the Development of the Oman Mountains Foredeep
Authors: Silva F. P. , Rodrigues J. F. , Maciel C. , Alomari S. 
Published: December 2007

Abstract
Recent studies on the geodynamics and tectonic evolution of Abu Dhabi showed that wrench tectonics played an important role on the deformation history of the area 1,2. This paper presents a new model for the northeastern Abu Dhabi based upon an integrated study which includes a recent reinterpretation of 3-D seismic from a major field located in that area, recent works on the Oman Mountains foredeep and associated rheological constrains. It highlights the importance of old structure and strike-slip tectonics in the structuration found at higher levels.
Review of Fractured Horizontal Wells Technology
Authors: Soliman M. Y. , Boonen P. 
Published: December 2007

Abstract
Since its introduction in the late 1980's, fracturing of horizontal wells has become a viable completion option. In certain reservoir conditions, horizontal wells offer significant production improvement over vertical wells, however, to maximize their return on investment, it may be necessary to fracture horizontal wells. This is especially true in case of tight gas formations.
This paper reviews the technology developed in the area of fracturing horizontal wells. The paper includes discussion on the rock mechanics, the operational, and the reservoir engineering aspects of fracturing horizontal wells.
The rock mechanics discussion reviews the various theoretical and experimental work that has been done in the area of fracturing horizontal wells. It also reviews the various phenomena such as creation of transverse and longitudinal fractures, creation of multiple fractures, and fracture reorientation among others that are associated with creation of a fractured horizontal well. Stability of the horizontal well as it relates to stimulation is also discussed.
The reservoir engineering portion of the paper discusses the production performance and testing aspects of a fractured horizontal well. Emphasis is given to fracturing tight gas formations, since this area is the one in which this technique is considered to be the most effective. The performance of a longitudinal fracture is examined and compared to a fractured vertical well and to the more popular transverse fractured horizontal well.
Because performance of a longitudinal fracture is similar to that of a fractured vertical well, the existing solutions for fractured vertical wells may be applied to longitudinal fractures. This approximation is valid for moderate to high dimensionless conductivity. In the case of transverse fractures, the outer fractures outperform the inner fractures. However, for most cases, more than two fractures are necessary to efficiently produce the reservoir.
Operational aspects of fracturing horizontal wells for both transverse or longitudinal fractures are discussed, and advantages and disadvantages of each type will be outlined. Examples and case histories are discussed. The paper also presents guidelines for stimulation of a horizontal well and includes both propped and acidized fracturing as well as matrix acidizing.
Nuclear Magnetic Resonance Logging: Can it Minimize Well Testing?
Authors: Petricola M. J. C. , Takezaki H. 
Published: December 2007

Summary
Over the past year or so, a new generation of nuclear magnetic resonance tools has been introduced in the Middle East. These tools, in contrast to the previous logging tool, the NML* introduced by Schlumberger more than 15 years ago, no longer require mud doping to kill the borehole signal. This greatly increases the number of candidate wells for this type of measurement.
In Abu Dhabi, a number of logs have been recorded in the Thamama, Shuaiba and Arab formations. These logs proved very challenging to interpret because very few nuclear magnetic resonance measurements have been made in carbonates until now. In particular, the relaxation times measured in Abu Dhabi were generally found to be longer than elsewhere. This was confirmed by extensive laboratory measurements on cores. This in turn means that it is extremely difficult to get a complete description of pore size distribution in continuous logging mode. However, experience has also shown that a representative value of the so-called "bound fluid volume", sometimes referred to as "microporosity volume", can be obtained even at "standard" logging speeds, i.e. 600 to 900 fph.
The microporosity volume is a very important piece of information in the carbonates of Abu Dhabi, because it can be related to the volume of irreducible water and therefore help in predicting whether a zone, even one with high water saturation, can produce water-free oil. If such information can be reliably and routinely derived from nuclear magnetic resonance data, it may help reduce the amount of well testing necessary in the appraisal of many wells.
In this paper we briefly review the basic physics of nuclear magnetic resonance measurements, discuss the effect that mud filtrate can have on the measurement, and present an example from the Arab formation where zones with high water saturation were perforated and produced oil without water.
A Review of Insulated Concentric Coiled Tubing Installations for Single Well, Steam Assisted Gravity Drainage
Authors: Falk Kelly , Nzekwu Ben , Karpuk Brad , Pelensky Peter 
Published: December 2007

Abstract
A new recovery process which uses concentric coiled tubing has been developed to improve production capabilities in heavy oil. The process, called Single Well – Steam Assisted Gravity DrainagePatPend (SW – SAGD) relies on continuous injection of high quality steam into the toe of a horizontal well while simultaneously producing mobilized oil from the same wellbore. The well is therefore dual completed with both, production tubulars and Insulated Concentric Coiled TubingPatPend (ICCT). Having completed an extensive study into the design and fabrication of ICCT, a number of single well, SAGD installations have already been completed and are in production. This paper will review this process and will document production results from some of these early wells.
A 2 3/8-in. Coiled-Tubing Recompletion in the Gulf of Mexico
Authors: Waguespack Sonny , Guichard Joel , Shamburger Jim , Meaux Joe , Trotter Tommy 
Published: December 2007

Abstract
An offshore well located in Eugene Island Block 384 in the Gulf of Mexico loaded up and ceased flowing. This behavior was attributed to an unstable flow regime caused by declining gas production in the field and by the large flow area of the 41/2-in. completion string. To re-establish stable flow, a smaller size production tubing was required to decrease the flow area and thereby increase gas velocities. Because of the declining production, mobilizing a worko ver rig to perform a recompletion was considered uneconomical. The well was evaluated for installation of a 2 3/8-in. coiled-tubing production string with packer, gas lift mandrel, landing nipples, and subsurface safety valve (SSSV) completion equipment. A coiled-tubing unit was mobilized, and the 2 3/8-in. coiled-tubing recompletion was successfully performed inside the existing 41/2-in. completion. The well was returned to stable production at approximately 40% of the cost of a workover-rig operation. This paper discusses the successful recompletion job design and field installation on the subject well and addresses the economic viability of using large-diameter coiled tubing as a permanent completion in offshore applications.
Computing Collapse Pressure for Coiled Tubing
Authors: Avakov Vladimir , Fowler Hampton 
Published: December 2007

Abstract
Other published literature discusses collapse pressure (CP) for round tubing,1 and proposes one collapse pressure (CP) expression for any OD-to-wall (D/t) ratio. This expression is easily solved and can be used with all units: US, metric, etc. CP for oval tubing was a subject of another paper.2
This paper presents available corrections of CP formulas including loading when external pressure is combined with internal pressure and axial force.
Achieving Extended Reach
Authors: Bhalla Kenneth 
Published: December 2007

Abstract
Extended reach technology (ERT) has allowed the petroleum industry to reach and capitalize on reserves inaccessible to conventional drilling and completion methods. ERT has developed rapidly in the UK and Norwegian sectors of the North Sea. Given the type of well profiles, conventional wireline techniques are not appropriate to convey tools and manipulate completion hardware. Coiled tubing (CT) is well suited to conduct such operations.
A limitation on the horizontal displacement occurs because of the frictional forces between the CT string and borehole while running in CT. This causes helical buckling and can lead to lockup of the CT, thereby limiting reach.
When coiled tubing is wound off a reel and bent over the gooseneck and then passed through the injector into the well, the coiled tubing undergoes plastic deformation and is subjected to residual bend. The residual bend imposes contact forces between the CT and the wellbore.
A CT straightener was developed to remove residual bend and improve extended reach. A description of the CT straightener experiments and trials will be outlined. Additionally, the various techniques currently in use will be addressed briefly.

Introduction
"The application of extended reach technology has resulted in extended field drainage radii, increased production rates, improved reservoir management, a reduction in required platforms and well counts and improved field economics…".
ERT has developed rapidly in the U.K., Norwegian and Danish sectors of the North Sea. Given the type of well profiles, conventional wire line techniques are not appropriate to convey tools and manipulate completion hardware. Due to the high angles of the long tangent sections combined with the TVD of the reservoir, such wells are known as extended reach wells. Coiled Tubing is well suited to conduct such operations. The definition of an extended reach well is a well with a measured depth to true vertical depth ratio (MD/TVD) greater than 2.0. A mega-reach well has a MD/TVD ratio greater than 3.0.
A New Approach to Calculate the Optimum Placement of Centralizers includes Torque and Drag Predictions
Authors: Kinzel Holger , Koithan Thomas , Lirette Brent 
Published: December 2007

Abstract
A good primary cementation requires careful selection of centralizers and their placement on the string. The centralizer placement algorithm described in the API-10D was corrected and put into a computer program. The standoff value is calculated based on the actual borehole geometry, string data and centralizer performance. The model was enhanced by a newly developed drag force simulation taking the centralizer running force into account. Additionally, the prediction of the expected torque values for rotating liner applications is included.

Introduction
The key factor for a successful cementation job is the replacement of the mud in the wellbore by the cement slurry. Hydraulic considerations call for the need of a good centralization of the string for all sections in which a good cementation is required. Centralizers have been used for decades to fulfill this job. Throughout the past couple of years, more and more designs of highly inclined, including horizontal, wells incorporate cemented production casing and liner sections. In these cases, the optimum placement of centralizers is achieved by balancing between a high standoff ratio and low drag forces.
A mathematical simulation model is used to calculate the optimum spacing of centralizers to obtain the best standoff at a given borehole location.
This model takes into account relevant factors, such as:–the lateral force at any given location based on borehole geometry, buoyed string weights and tension forces–the centralizer's reaction to these forces, based on test data for each pipe size/hole size combination–the sag between centralizers based on the elasticity of the pipe and a three-dimensional vector analysis of the weight and tension components.
This mathematical model is associated with a torque and drag analysis, utilizing the known running forces of the centralizers and the friction factors that depend on the mud type. This analysis is important in order to evaluate whether the desired centralizer spacing can be run or rotated without creating problems due to high drag forces, or damage to the pipe connections. The equations upon which these models are based and the computer algorithms used are described in this paper.

2 Maximize Standoff and Minimize Drag
Various models have been described in the literature to calculate the centralizer placement.
The criteria to select a centralizer pattern should be not only the achieved centralization but, especially in highly inclined wells, the ability to move the string. Thus, drag and torque calculation should be a part of the centralizer placement calculation.
It is important to understand that all mathematical equations and relationships regarding centralizer placement describe a model situation only. The actual standoff in a borehole depends on many different factors. There is no method of actually looking into the well and no tool like a "Standoff-Logging-Tool" to provide this information directly.
P. 153
The Effects of Pressure and Rotary Speed on the Drag Bit Drilling Strength of Deep Formations
Authors: Kolle J. J. 
Published: December 2007

Abstract
Shear induced dilatancy of rock during drag bit cutting in deep formations can result in dynamic confining pressures that equal the borehole pressure and increase the drilling strength. Rock cutting experiments were carried out in five sedimentary rock types with widely varying permeability, porosity and strength to test a model of dynamic confinement. Indentation and shear loads on thermally stabilized diamond (TSD) cutters were obtained at pressures of up to 70 MPa and at traverse rates ranging from 0.5 to 8 m/s. Ambient pressure causes rate-insensitive drilling strength hardening in the low-permeability shale and carbonate and rate-sensitive hardening in the permeable sandstones. These results are predicted by the dynamic confinement theory. An analysis of indentation load versus cut depth shows that cutter wear in all five rock types should be minimized at high rotary speeds and shallow depths of cut in deep formations.