bluuebunny/crossref_metadata_2025 huggingface dataset:
Operating Experience of ESP's in South Oman
Authors: Norris Chris , Al-Hinai Saif H.
Published: December 2007

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

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.

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

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

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

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

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

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

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

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

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

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

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

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

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.
Nuclear Magnetic Resonance Applied to Gas Detection in a Highly Laminated Gulf of Mexico Turbidite Invaded with Synthetic Oil Filtrate
Authors: Moore M. A. , Akkurt R.
Published: December 2007

A recently developed time-domain nuclear magnetic resonance (NMR) technique applying matched filters to the difference of raw echo trains acquired with different wait times has proven effective in detecting and quantifying free gas in a highly laminated Gulf of Mexico (GOM) turbidite deposit expected to be badly invaded by synthetic oil-base drilling fluid. This case history is the first documented use of this approach under these conditions, and it clearly met objectives where the more conventional differential spectrum method (DSM) failed.

The technique was applied to data acquired in the Shell-operated Tahoe Field. The VK783 #5 penetration encountered one-hundred-seventy gross feet of laminated turbidite reservoir averaging 50% net to gross through much of the interval. The well was thirteen-hundred psi overbalanced, and this, combined with the miscible filtrate made severe invasion and near residual gas saturations a certainty near the wellbore. Conventional wireline gas indicators such as neutron-density crossover and the various cross plots fail in this environment due to tool inability to resolve the sand beds and to the abundance of shale laminae, and is aggravated by the invasion. Fluid typing is primarily done with fluid pressure gradients established via formation tester. For this well, the logging program included quad-combo, NMR (MRIL-C®) and formation tester. The formation tester proved gas to base in the reservoir, showing a .0951 psi/ft fluid pressure gradient.

The conventional DSM analysis carried out in the T2 domain showed a strong signal from the invading filtrate, but was ambiguous with respect to gas detection. Careful examination of the raw echo train data using matched filters showed clearly both heavy filtrate invasion, and the presence of gas in low saturations. This result is a significant advance in turbidite formation evaluation, providing our petrophysical toolbox with a new, powerful fluid typing tool that has proven effective even under very challenging conditions.
A Hybrid, Neuro-Genetic Approach to Hydraulic Fracture Treatment Design and Optimization
Authors: Mohaghegh S. , Balan B. , Ameri S. , McVey D. S.
Published: December 2007

This paper summarizes the efforts conducted toward the development of a new and novel methodology for optimal design of hydraulic fracture treatments in a gas storage field. What makes this methodology unique is its capability to provide engineers with a near optimum design of a frac job despite very little (almost none) reservoir data availability. Lack of engineering data for hydraulic fracture design and evaluation had made use of 2D or 3D hydraulic fracture simulators impractical. As a result, prior designs of hydraulic frac jobs had been reduced to guess works and in some cases dependent on engineers with many years of experience on this particular field, who had developed an intuition about this formation and its possible response to different treatments. This was the main cause of several frac job failures every year. On the other hand, in case of relocation of engineers with experience on this particular field the risk of even more frac job failures was imminent.

The unique design optimization method presented here is a logical continuation of the study that was covered in two previous papers1,2. To thoroughly understand this methodology, reading of these two references are highly recommended. This method will accept available data on each well, which includes basic well information and production history, and provides engineer with a detail optimum hydraulic fracture design unique to that well, along with the expected post-frac deliverability. Please note that there are no simulated data throughout this study and all data used for development and verification of all methods are done using actual field data.
Reengineering Simulation: A Bottom-Line Approach to Managing Complexity and Complexification
Authors: Saleri Nansen G.
Published: December 2007

Managing complexity and technological complexification is a business need. The paper outlines a methodology to significantly increase value-addition by multi-disciplinary reservoir studies. It ensures a level of complexification in line both with business questions at hand and the realities of reservoirs.
Analytical Gas Pipeline Design Method Using The GERG Equation of State
Authors: Yildiz Turhan
Published: December 2007

This study presents a new analytical method to design gas pipelines. The new method is based on a real gas equation of state developed by The European Gas Research Group (GERG). This equation of state is very accurate in the pressure and temperature ranges that gas pipelines are operated at. The form of the GERG equation of state is such that an analytical solution to compressible gas flow in an arbitrarily inclined flow string can be obtained.

The new analytical method considers the effect of kinetic energy, variable temperature distribution along the flow string, changes in flow string inclination, and variable flow string size, all of which are not considered in available methods in the literature. This method can be applied to both gas pipelines and wells. The new method is verified by comparing model-calculated and field-measured pressure drops in gas pipelines and gas wells. Twenty-seven data set for pipelines are used in the comparison. The average difference between calculated and measured pressure losses is 3 psi for pipelines.

The methodology used to develop the new method can also be used to solve other gas flow problems.
Statistical Analysis of Well Productivity in Heterogeneous Reservoirs
Authors: Lee K. S. , Miller M. A. , Sepehrnoori K.
Published: December 2007

The effect of reservoir heterogeneity on the productivity of wells in closed depletion reservoirs is investigated. A direct pseudosteady-state equation solution, derived using the divergence theorem, is used to conduct an extensive stochastic simulation study at greatly increased computational efficiency. Dozens of permeability fields corresponding to various Dykstra-Parsons coefficients and correlation lengths are generated using geostatistical simulation techniques. The pseudosteady-state equation is solved by a finite-element method in 2D heterogeneous reservoirs. Pressure drawdown is calculated from the solution. Results are analyzed statistically to examine the effects of geostatistical parameters of reservoir heterogeneity on well productivity during pseudosteady-state.

Analysis of the results show that the properties of the pressure drawdown frequency distribution function are sensitive to structure (well-block permeability) and intensity (Dykstra-Parsons coefficient), but weakly to connectivity (congelation length). Bivariate analysis indicates that the logarithm of pressure drawdown is linearly correlated with the logarithm of the well-block permeability, and that spatial connectivity of permeabilities affects the correlation. Comparison with the behavior of equivalent homogeneous systems provides quantification of an additional pressure loss due to reservoir heterogeneity as a function of Dykstra-Parsons coefficient and correlation length.
Evaluating Formation Damage Risks in a Glauconitic Sandstone Reservoir: A Case History from the Offshore North West Shelf of Australia
Authors: Hatcher G. B. , Chen H. , Rahman S. S. , Hogg P. F.
Published: December 2007

When exploiting hydrocarbon reserves in lithologically and petrophysically complex glauconitic sandstones, potentially damaging fluid/rock and fluid/fluid interactions must be thoroughly investigated. This paper reports on the first phase of a comprehensive, multi-disciplinary study of such interactions conducted on samples from the Saladin field, located on the offshore North West Shelf of Australia. Core floods indicate that the formation is not susceptible to significant damage during the flow of simple brines. However, chemical analysis of core flood effluents after periods of stasis indicate continuing interactions between introduced fluids and fluids resident in the large volume of microporosity. Awareness of such delayed interactions will be important in restored state core analysis and when evaluating the damage potential of more complex fluid systems. The reservoir was found to suffer extreme damage on exposure to freshwater. The sum of evidence suggests that swelling of glauconitic smectite is the underlying cause of the damage, with pore throat plugging by mobilised glauconitic smectite and non-expandable glauconitic clays the probable damage mechanism. Saturation with calcium chloride solutions prevented water shock damage.
Horizontal Well Application: Reservoir Management
Authors: Joshi S. D. , Ding W.
Published: December 2007

A successful horizontal well project requires well-defined management objectives. These objectives may include increase of production rate, acceleration of reserves, addition of low cost reserves, improvement of economic benefit, etc. These objectives can be achieved by 1) reducing undesirable fluid production and thereby, reducing surface facility cost, 2) producing "lost" reserves in thin oil rim, 3) reducing the number of injection and production wells required for development of a new field, redevelopment of a mature field or infill drilling program, and 4) bringing on-stream currently unused wells by sidetracking.

The purpose of this paper is to review the applications of horizontal wells in reservoir management, discuss its advantages and summarize the reservoir parameters that are critical for a commercially successful project
A New Method to Predict Performance of Fractured Horizontal Wells
Authors: Li Hujun , Jia Zhengqi , Wei Zhaosheng
Published: December 2007

When an oil field with low permeability oil reservoirs is developed with horizontal wells, hydraulic fracturing is usually necessary to achieve an economic oil production rate. It is necessary to find a method for predicting performance of fractured horizontal wells. A practical method to predict performance of a horizontal well which is hydraulically fractured and partially perforated has been proposed in this paper. Using the mathematical model presented in this paper, factors affecting performance of a hydraulically fractured horizontal well have been analyzed. Two oilfield cases from the Daqing Oilfield are analyzed using the method and presented in this paper. Calculations and analyses show that the results which are calculated using this method are consistent with the actual results from the oilfield.
Stimulation of Horizontal Wells Using the Dynamic Gas Pulse Loading Technique
Authors: Loman G. , Phillips D. T. , Cicon H. N.
Published: December 2007

This paper describes the application of Dynamic Gas Pulse Loading (DGPL)1,2 in horizontal wells with open hole, predrilled loose liner, and slotted liner completions. Peak pressures generated by DGPL, which were recorded at intervals along the horizontal trajectory within the selected treatment segment, clearly show local variations in the breakdown pressure of the homogenous formation.
Laboratory Evaluation of Drilling Mud Systems for Formation Damage Prevention in Horizontal Wells
Authors: Shaw J. C. , Chee T.
Published: December 2007

Drilling-induced formation damage has played a significant role in the failure of some horizontal wells. The objective of this laboratory study is to provide insights into this complex subject by investigating the main formation damage mechanism(s) and systematically quantify the damage effect caused by the newly formulated drilling mud systems, which are designed to minimize formation damage.

Eleven commercial drilling mud systems were tested in this study and they produced a very wide range of permeability reduction on Berea sandstone cores with similar properties. Bentonite and cellulose based bridging agents appear to cause higher degrees of damage than ground calcium carbonate. High acid solubility of these muds is conducive to much improved permeability after acid stimulation.

Results of additional dynamic mud leak-off experiments show that the most important parameters which affect regained permeability are: 1) mud composition, 2) core permeability, 3) overbalance pressure, 4) filter cake rigidity, 5) pressure drawdown during backflow, and 6) mud particle versus rock pore-throat size distribution. The depth of mud solid invasion is limited to the first few centimetres of the injection end but the filtrate usually invades the whole core. Furthermore, repeated removal of the existing mud cake can cause much deeper invasion and more severe damage.
Kinetics of the Secondary Reaction of HF on Alumino-Silicates
Authors: Gdanski Rick
Published: December 2007

The standard description of HF acidizing chemistry clearly demonstrates a primary and secondary reaction of HF with alumino-silicates.1 Field experience has taught us that possible precipitation during the secondary reaction can adversely affect treatment success,2 especially in formations with high K-feld-spar content or temperatures above 300°F. Recent work has also reported the existence of a third, or tertiary reaction, of HF with alumino-silicates.3

This paper reports the determination of the rate law for the secondary reaction and the kinetics for that reaction on kaolinite and feldspar over a broad temperature range. In addition, the kinetics of fluosilicate precipitation during the secondary reaction were studied and found to be fast but not instantaneous. These findings were made possible by recently applied experimental techniques including 19F NMR spectroscopy, 3fractional pore volume flow experiments,4 and an accurate knowledge of the HF stoichiometry.5 Laboratory findings have been verified based on detailed analysis of flowback samples from field treatments.6

The reaction rate for the secondary reaction is much slower on feldspars than on clays. At temperatures below 125°F, the secondary reaction rate is very slow, which makes spent HF susceptible to fluosilicate precipitation if the HF is mixed with brines as it often is for disposal or injection well treatments. The difference in the kinetics between clays and feldspar allows one to design treatments at lower temperatures based on just the clay fraction. At temperatures above 150°F, the average mineralogy, clay mineralogy, and feldspar mineralogy should each be evaluated separately for potential fluosilicate precipitation. The fluid of choice is the one that passes all three conditions.

The rate law indicates that the speed of the reaction is independent of HCl concentration and would proceed to completion even in the absence of HCl. Chemically, one can accomplish this effect by using water as a proton source and by adjusting the stoichiometry based on a previously reported equilibrium.5 The kinetics for fluosilicate precipitation were fast but not instantaneous. At very high temperatures, the secondary reaction is fast enough that fluosilicate precipitations can largely be avoided. Unfortunately, the silica gel precipitation then occurs so close to the wellbore that damage to permeability will likely occur. The equations recently developed for the HF acidizing process have been incorporated into a fully kinetic geochemical radial flow simulator. Calculations performed with this simulator have confirmed that a good knowledge of the formation mineralogy and acidizing kinetics is necessary for proper optimization of HF acidizing treatments.
Enhanced Foams for Efficient Gas Influx Control
Authors: Dalland Mariann , Hanssen Jan Erik
Published: December 2007

The paper presents new experimental results from laboratory studies on the use of gas-blocking foams for controlling gas influx into production wells. Foam performance is measured using the well-qualified gas-blockage test procedure at the conditions of four reservoirs where pilot testing of foams is currently planned or on-going. New foam formulations are described where polymer is incorporated into the foaming-agent formulation. For one reservoir, cross-linking chemicals have also been included, allowing comparison of conventional foams stabilised only by surfactant, polymer-fortified foams, and gelled foams.

The results show that strongly improved gas-blockage performance may be obtained by addition of polymer to the foaming-agent solution. In the most favorable cases, foams of essentially no gas-blocking ability can be transformed to very efficient gas-blocking agents by adding polymer. However, in some (repeated) experiments, polymer addition did not result in a better gas-blocking foam, and concentration effects are observed so that adding too much polymer can give sharply reduced foam efficiency. Gel foams also are not necessarily superior to polymer foams as gas-blocking agents.

It is concluded that polymer-enhanced foams are of great potential value for gas influx control, but that more knowledge of surfactant/polymer interaction in the thin film network that constitutes the foam is required in order to predict the effects of adding polymer to gas-blocking foam formulations.
A Novel Surfactant for Oilfield Applications
Authors: Borchardt John K.
Published: December 2007

Previously, esters of alcohol ethoxycaiboxylates have been developed for use in surfactant flooding, micellar polymer flooding, and foam flooding enhanced oil recovery. With the increased availability and improved economics of alcohol ethoxycarboxylate surfactants due to commercialization of a more cost-effective synthesis, additional applications of AEC's are being developed. Among these are various oilfield applications.

Foaming data at neutral and basic pH suggest that AEC surfactants could have applications as foaming agents for hydraulic fracturing, acidizing, drilling, and completion fluids. AEC surfactants foam more readily in basic media than in acidic media. However, AEC surfactants form stable foams in acidic media, foams even more stable than basic media foams. So while AEC surfactants could be useful foaming agents in hydraulic fracturing, normally carried out in basic media, they could also be useful as foaming agents in acidizing and acid fracturing.

Taken together, dynamic surface tension values, contact angle measurements, and interfacial tension values suggest that AEC surfactants could have applications in acidizing whether or not they are used as foaming agents
A Novel Technique to Characterize Oxidative Encapsulated Breakers Used in Fracturing Fluids
Authors: Rao Ajoy , Elliff Chris , Bilden Dean
Published: December 2007

Oxidative breakers are used extensively to degrade the polymers used in oil and gas well hydraulic fracturing fluids. These oxidative breakers react extremely fast in most downhole environments and can degrade fracturing fluids at rates that are undesirable. To increase the stability of fracturing fluids, these oxidative breakers have been encapsulated, with various techniques, to delay the release of the breaker into the aqueous environment and cause a delayed break or degradation of the fracturing fluid. Historically, evaluation of the release rates has been accomplished by measuring the degree and rate of viscosity degradation in laboratory rheometers. These tests are very time consuming and somewhat subjective.

A new methodology is provided to characterize encapsulated oxidative breakers (EOB) using Thermogravimetric Analysis (TGA). The new approach is based on weight loss using constant or dynamic heating rates. The novel technique constitutes a powerful tool to characterize the product complementary to conventional laboratory tests which are time consuming.

This technique can be used to streamline the developmental process used in manufacturing these encapsulated oxidative breakers. It is also extremely beneficial for QA/QC of this type of product. The quality of these products can be determined in much less time and with better precision than conventional techniques. Relevant literature references have been identified and are included in the paper.
Reaction Rate and Fluid Loss: The Keys to Wormhole Initiation and Propagation in Carbonate Acidizing
Authors: Huang T. , Hill A. D. , Schechter R. S.
Published: December 2007

The efficiency of the matrix acidizing process in carbonates depends strongly on the wormholing phenomenon—if wormholes are formed, the effects of near wellbore damage can be overcome with relatively small volumes of acid. Numerous previous studies have shown that wormhole patterns can be placed in these general categories: (1) compact dissolution in which most of the acid is spent near the rock face; (2) the wormholing pattern; and (3) uniform dissolution in which many pores are enlarged, as typically occurs in sandstone acidizing. We have developed a theory of the wormholing process which predicts when the wormholing pattern is most efficiently created as a function of the acid flux and other treatment variables.

By testing this theory with several independent sets of laboratory data, we can now demonstrate the important roles that surface reaction rate and fluid loss play in the wormholing process. This theory accurately predicts the optimal flux (that which leads to dominant wormholes with a minimum of branching and hence a minimum acid volume) for experiments with HCl in limestone and dolomite at several temperatures and with acetic acid in limestone. Surface reaction rale differs by several orders of magnitude in these experiments and is the only process variable that differs greatly among them. Paradoxically, though wormholes are formed because the overall reaction rate is controlled by mass transfer in the wormholes, diffusion rates play only a minor role in the wormholing process.

Fluid loss through the walls of the wormholes ultimately limits the distance to which wormholes can propagate. Because of this effect, laboratory linear core floods will give optimistic predictions of wormhole penetration distances. We developed a cylindrical flow model to represent the flow field around a wormhole propagating from a wellbore which illustrates how to translate laboratory results to field conditions.

We have used these theories to predict optimal acid formulations and injection rates for field conditions. In general, the lower the reaction rate (such as at low temperatures in dolomites or with weak acids in limestones), the lower the injection rate required, making it easier to propagate dominant wormholes under matrix treating conditions in the field.