bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using High-Frequency Downhole Vibration Technology to Enhance through-Tubing Fishing and Workover Operations
Authors: Joppe L. C. , Mackenzie G. , McGurk M. 
Published: December 2007

Abstract
In coiled tubing conveyed through-tubing fishing operations, conventional jarring technology often creates limitations due to the requirement to repeatedly cycle the coiled tubing over the gooseneck in order to actuate and re-cock the jar. It is well known and documented in our industry that this repeated cycling leads to pipe fatigue and coiled tubing life reduction. Additionally, the low frequency, high-impact of the jarring assembly, may in some cases cause the fish to become wedged tighter.
Vibratory and high frequency impact tools have been found to provide operational and economic benefits over hydraulic, time delayed jarring tools in a variety of through tubing fishing and workover applications, particularly in horizontal and extended-reach wells.
As opposed to jars, vibratory type impact systems are capable of delivering significant impact forces at the fish with only limited set-down weight or over pull available making them particularly well suited to the constraints of coiled tubing operations. These hydraulically powered systems are configured to deliver downward impacts in compression and upward impacts in tension. Both downward and upward impacts are achieved without the necessity to cycle the coiled tubing between impacts, therefore significantly reducing low-cycle pipe fatigue. Additionally, when a fish is stuck in sand or debris, temporarily suspending or liquefying sand particles by lighter high frequency blows as delivered by an impact tool while over pull is applied offers a higher degree of success in freeing the fish.
This paper will outline the uses and advantages of down-hole high-frequency vibration technology from a coiled tubing perspective and also describe the development and laboratory testing results of a new, modular vibratory impact tool offering a significantly reduced operating length yet delivering greater impact thus increasing the operating envelope for such tools adding demonstrable value to a variety of coiled tubing fishing and workover operations.
Gas Hydrates and Deepwater Operation: Predicting the Hydrate-Free Zone
Authors: Mohammadi A. H. , Tohidi B. 
Published: December 2007

Abstract
The application of extended subsea networks and transportation of unprocessed well-streams are amongst favorable options for reducing field development and operational costs. These pipelines normally convey a cocktail of multiphase fluids, including mixed electrolyte produced water and liquid and gaseous hydrocarbons and may therefore be prone to hydrate formation, which potentially can block the pipe and lead to serious operational problems. For deep water operation, even saturated saline solutions may not provide the required protection, unless combined with chemical inhibitor. The reported data on hydrate formation in mixed salt and chemical inhibitor are very limited and in some cases inconsistent.
In this work, a model is introduced to predict the hydrate free zone in mixed salt and chemical inhibitor designed for offshore and deep water applications. The model is based on combination of the Valderrama modification of the Patel-Teja equation of state with non-density dependent mixing rules and a modification of a Debye-Hückel electrostatic term, which is applied to systems containing salt and chemical inhibitor by correcting the properties of the aqueous phase such as dielectric constant, density and molecular weight. A linear mixing rule is used for determining the dielectric constant of salt-free mixture by introducing an interaction parameter (in dielectric constant mixing rule), which is tuned using the freezing point data of aqueous solutions containing salt and organic inhibitor. The binary interaction parameter between salt and organic inhibitor is adjusted using water vapor pressure data in the presence of salt and organic inhibitor. The predictions are compared with experimental data and a literature model, demonstrating the reliability of the developed model.
Sweep Improvement Options for the Daqing Oil Field
Authors: Wang D. , Han P. , Shao Z. , Chen J. , Seright R. S. 
Published: December 2007

Abstract
This paper investigates the potential of various approaches for improving sweep in parts of the Daqing Oil Field that have been EOR targets. Possibilities included (1) gel treatments that are directed at channeling through fractures, (2) colloidal dispersion gels, (3) reduced polymer degradation, (4) more viscous polymer solutions, and (5) foams and other methods. Our studies indicated that the polymer flood should have provided excellent sweep throughout the vast majority of the patterns under consideration. However, since ASP flooding is being considered to increase recovery efficiency from the Daqing Oil Field, mobility control and sweep improvement will be especially important and challenging during implementation of any future ASP process.
Fractures were present in a number of Daqing wells (both injectors and producers). Because the fractures were narrow far from the wellbore, severe channeling did not occur. On the contrary, fractures near the wellbore aided reservoir sweep. These near-wellbore fractures substantially increased the injectivity index during injection of polymer solutions and increased oil productivity index in the production wells. These observations may be valuable during implementation of future floods where very low-mobility chemical (i.e., ASP) banks must be injected to maintain mobility control.
Several modes of polymer degradation were considered, with mechanical (shear) degradation being of most concern. Appropriate use of near-wellbore fractures may effectively mitigate mechanical degradation, as well as improving injectivity.
Several new polymers show potential for cost-effective improvements at Daqing. Increased polymer concentration was also considered. A number of other approaches are (or have been) under investigation, including colloidal dispersion gels, foams, ASP foams, steam, microbes, and polymer solutions prepared with reduced salinity.
Compressible Streamlines and Three-Phase History Matching
Authors: Cheng H. , Oyerinde D. , Datta-Gupta A. , Milliken W. 
Published: December 2007

Abstract
Reconciling high-resolution geologic models to field production history is still by far the most time-consuming aspect of the workflow for both geoscientists and engineers. Recently streamline-based assisted and automatic history matching techniques have shown great potential in this regard and several field applications have demonstrated the feasibility of the approach. However, most of these applications have been limited to two-phase water-oil flow under incompressible or slightly compressible conditions.
We propose an approach to history matching three-phase flow using a novel compressible streamline formulation and streamline-derived analytic sensitivities. First, we utilize a generalized streamline model to account for compressible flow by introducing an ‘effective density’ of total fluids along streamlines. This density term rigorously captures changes in fluid volumes with pressure and is easily traced along streamlines. A density-dependent source term in the saturation equation further accounts for the pressure effects during saturation calculations along streamlines. Our approach preserves the 1-D nature of the saturation equation and all the associated advantages of the streamline approach with only minor modifications to existing streamline models. Second, we analytically compute parameter sensitivities that define the relationship between the reservoir properties and the production response, viz. water-cut and gas-oil ratio (GOR). These sensitivities are an integral part of history matching and streamline models permit efficient computation of these sensitivities through a single flow simulation. Finally, for history matching we use a generalized travel-time inversion that has been shown to be robust because of its quasi-linear properties and converges in only a few iterations. The approach is very fast and avoids much of the subjective judgments and time-consuming trial-and-errors inherent in manual history matching.
We demonstrate the power and utility of our approach using both synthetic and field-scale examples. The synthetic case is used to validate our method. It entails the joint integration of water cut and gas oil ratios from a 9-spot pattern in reconstructing a reference permeability field. The field-scale example is a modified version of the ninth SPE comparative study and consists of 25 producers, 1 injector and aquifer influx. Starting with a prior geologic model, we integrate water-cut and GOR history via the generalized travel time inversion. Our approach takes only a few hours on a PC for the entire history matching while preserving the geologic continuity.
Experimental Evaluation of the Blockage Efficiency of a Novel Gel System To Mitigate Water-Cut Problem of Producing Wells
Authors: Amanullah M. 
Published: December 2007

Abstract
Water production is a problem of paramount importance from technical, environmental and oil production points of views. The processing, treatment and disposal of produced water cost millions of dollars for a single field. On the other hand, high water production causes a drastic reduction in oil production. The issue of excessive water production has been addressed by the industry by placing different gel system in the reservoir to block the water flow and facilitate the oil flow. The most commonly used solutions are polymer gels with chromium (Cr3+) as the cross-linking agents in the gel system. Some of the polymer gel systems are not effective at temperature above 70 °C due to the thermal and hydrolytic degradation of the polymer. Moreover, the precipitation of the toxic cross-linking agent with increased temperature and pH is a major environmental concern.
This paper describes the water blocking efficiency of an environment friendly and biodegradable gel system to mitigate the water cut problem of producing wells. The newly designed gel system has no cross-linking agent and is stable up to 194 °F (90 °C) temperature. The system is stable in the presence of divalent ions and also in a range of pH conditions. Experimental results indicate nearly 100% reduction in water permeability of 16/30 sand-pack after treatment. Flow test with mineral oil indicate higher oil permeability compared to water. However, oil permeability has been reduced dramatically compared to pre-treatment oil permeability. Hence, it is most suitable for treating the water zone of a reservoir.
More and More From Brownfields—A Structured Process To Deliver Value
Authors: Seong C. K. , Malek R. A. 
Published: December 2007

Abstract
Since 1996, PETRONAS has implemented a structured field development plan review process with its PS Contractors to maximize reserves and value from the brown fields. Even though every stage of the FDP Milestone Review has a clear objective and expectation, yet PMU and PS Contractors approach the review differently. Understanding the PS Contractors mindset is key to managing differing views. This paper will describe (i) PETRONAS roles and objectives as the national oil company – in relation to management of petroleum resources, (ii) the structured brown field development plan review process, in particular the four critical Milestone Review and its related key activities, (iii) observable differences between PMU and PS Contractors during each Milestone Review and some applicable rules used by PMU to manage the situation. As a result of this implementation, reserves addition have been realized, value created and cycle time for brown field development plan approval has reduced significantly. It should be noted that the structured field development plan review process is also applicable to the green field development, with some changes to the process.
Improved ASP Process Using Organic Alkali
Authors: Berger P. D. , Lee C. H. 
Published: December 2007

Abstract
This paper describes the use of a new type of organic alkali that replaces and improves upon traditional inorganic alkalis such as sodium hydroxide and sodium carbonate. The new organic alkali was evaluated in Alkaline Surfactant Polymer (ASP) formulations containing commonly used surfactants and polymers. The effect of organic alkali on IFT, adsorption and viscosity was compared to that of a conventional inorganic alkali in these formulations. The organic alkali was found to be compatible with brines containing high TDS and high divalent cation concentrations. They can be used in brines without the need for softening and in some cases they provide better results than conventional alkali in systems where either can be used. The organic alkalis have the advantage of improved compatibility with unsoftened brines, surfactants and polymers. Their non-toxic, biodegradable properties make them particularly suitable for environmentally sensitive applications such as offshore and inland lakes.
How Far Can a State-of-the-Art NPV Model Take You in Decision Making?
Authors: Pedersen F. B. , Hanssen T. H. , Aasheim T. I. 
Published: December 2007

Abstract
The mature North Sea hydrocarbon province is often referred to as a guiding star, indicating changes the E&P industry soon will experience in other parts of the world. A number of the recent North Sea development concept decisions have ranked high in complexity. Most of these fields have so far been regarded as sub-economic. The recent oil price increase has sparked renewed interest, but the underlying risks are unchanged. Complex and interdependent risks in reservoirs and fluid regimes, unclear third-party options, CAPEX and OPEX risks, schedule risks and costs of rectifying equipment failure all constitute challenges to finding the optimal concept selection.
This complexity is relatively easily integrated in a full probabilistic economic model, yielding powerful inputs to concept ranking, design debottlenecking and illumination of the needs for flexible development plans and inbuilt excess capacities. However, such models will add most value within a risk-based decision making framework, with clearly defined decision criteria and identification of the key external risk factors.
In this paper we take a look at good practices for concept definition, qualitative screening and NPV ranking, focusing in particular on a risk-based decision framework. We discuss how soft issues in many cases set aside the recommendation from the quantitative model and finally look into the need for better communication between modellers and decision makers.
Wellbore Stability Assessment for Highly Inclined Wells Using Limited Rock-Mechanics Data
Authors: Simangunsong R. A. , Villatoro J. J. , Davis A. K. 
Published: December 2007

Abstract
Assessment of wellbore stability involves several parameters for which data that may not be readily available. The rock mechanics input data required for analysis are complicated and costly to acquire. Nevertheless, wellbore stability assessment plays an important role in the design of drilling and production of oil and gas wells; therefore, a methodology for bridging the data gap is needed.
This paper presents a methodology for wellbore stability assessment with limited data, using common reservoir data. The methodology provides correlations for estimating in-situ stress regimes based on the regional data and rock mechanics parameters based on its lithology. Afterwards, in-situ stress and rock mechanics parameters are used to investigate the effect of stress anisotropy on the mechanical stability of the borehole for various inclination angles.
Three failure criteria are reviewed to assess borehole stability, namely Mohr-Coulomb, Drucker-Prager, and modified Lade criteria. These failure criteria are combined with linear and isotropic rock mechanics behavior.
Evaluation of stress behavior of a variety of rock lithologies was performed, using failure criteria. Results indicate that the modified Lade criteria tend to be more realistic than the Mohr-Coulomb and Drucker-Prager criteria for these evaluations. Furthermore, this study confirms that, for any type of rock, an increase in borehole inclination angle increases the risk of borehole instability. Sensitivity analysis, based on various reservoir parameters, is performed and confirms the reliability of the correlations reviewed.
The methodology presented here can be used as an indicator of borehole instability risk before drilling. Subsequently, the results can be used to optimize drilling design and enhance safety in drilling operations.
Simulation of Experimental Gas-Recycling Experiments in Fractured Gas/Condensate Reservoirs
Authors: Shadizadeh S. R. , Rashtchian D. , Moradi S. 
Published: December 2007

Abstract
Gas recycling experiments were conducted on a gas condensate sample in a fractured model. Experimental Model was then numerically simulated with compositional simulator. The objectives were to investigate effects of gas recycling on condensate recovery from a naturally fractured reservoir under complete pressure maintenance process.
In laboratory scale we could accurately analyse behavior of in-place and injected gas in fracture and matrix blocks and understand how the production mechanisms affect ultimate recovery in this reservoir model. In reservoir scale, due to high heterogeneity and lack of required data such an accurate investigation is impossible.
In the simulated model after history matching of cumulative gas and condensate production and composition variation history of produced gas, some sensitivity analysis were performed. Simulation results show that gas recycling increases liquid recovery more than 2.5 times for the reservoir if the fracture model behaves as dual permeability fractured reservoir. If model behavior supposed to be dual porosity, condensate recovery decreases dramatically due to early break through of injected gas via fractures. Cyclic injection-production and decreasing the production rate are the factors directing the process to higher ultimate recoveries. Nitrogen injection effect has also been established showing less recovery than dry gas injection case.
Finally, lacks of data for a complete compositional simulation of such models are mentioned. If the data be prepared prior to performing the experiment, results could be up-scaled to the reservoir with higher degree of assurance.
First Through-Tubing Gravel-Pack Recompletion Performed in Japan
Authors: Numasawa M. , Salahudin S. , Hashimoto H. , Choy C. Y. , Mitsuda S. 
Published: December 2007

Abstract
Japan Petroleum Exploration Co., Ltd (JAPEX) and Mitsubishi Gas Chemical Company Inc. (MGC) operate the Higashi Niigata Oil & Gas Field in Niigata, Japan. One of the wells, NS-6, a gas producer, had produced a large amount of formation sand, which filled up the surface production facility and production tubing resulting in production being shut-in at the end of 2002.
This paper will discuss a workover performed on this well, which was conducted in an effort to extend well life. Due to the depleted nature of the reservoir, a through-tubing gravel pack was chosen as the means to re-complete the well. The through-tubing gravel pack service was supplied by a local service company working in co-operation with a specialist through-tubing service provider who also provided onsite installation supervision. This method of through-tubing remediation was the first time this type of installation was used in Japan.
The local service company personnel with support from their Malaysia sand-control team worked with the customer and the specialist through-tubing service provider to design the job, and as a result of their expertise, the job was successfully performed. This case history will discuss 1) the planning and successful execution of the job, 2) its cost efficiency and safety, 3) its capability to meet majority of JAPEX’s and MGC’s goals, and 4) the valuable experience it provided for planning future remedial activities that may be required in this field.
Optimization of Conformance Decisions Using a New Well-Intervention Simulator
Authors: Ansah J. , Soliman M. Y. , Ali S. , Moreno C. , Jorquera R. , Warren J. 
Published: December 2007

Abstract
For many years, operators and service companies have applied conformance treatments without adequate methods to verify treatment efficiency, since complexities of the treatment and reservoir systems have made attempts to quantify the effects of these conformance solutions with available tools unreliable. A comprehensive database had been developed with help of several operating companies of conformance treatments that were performed by several service companies over 30+ years. This database shows that in the absence of proper diagnostics and analysis, the success of a conformance treatment usually hovers around 50% even in well established areas. Application in new areas usually fares significantly worse, with a success ratio of 30% or less.
An important reason for this unacceptable situation is the tendency to design a conformance treatment without adequately considering reservoir effect. In this paper, we present a methodology and a numerical simulation approach that are aimed at improving the success ratio of conformance treatments.
Optimum conformance treatments must consider: placement techniques,treatment size,reservoir temperature and pressure effects, andtracking of conformance fluid-property changes with time and temperature.
To adequately design a conformance treatment, it is important to predict both pressure and temperature profiles inside the wellbore and the reservoir. Using a numerical simulator that couples the wellbore with the reservoir provides a very efficient means for developing a methodology to optimize conformance treatments. Simulated examples are given to shed insight into basic conformance phenomena such as coning and channeling. Most importantly, two field cases are presented to demonstrate practical application of the developed methodology for designing an optimum conformance solution.
This new methodology reduces operational and economic risks associated with conformance treatments. It also allows for optimization of these treatments through more accurate prediction of water and hydrocarbon production.
The Effect of Sulfur Deposition on Gas Deliverability
Authors: Mei H. , Zhang M. , Yang X. 
Published: December 2007

Abstract
Sour gas reservoirs with high content of sulfur are distributed widely around the world. Solid elemental sulfur which dissolves in the gas phase originally in the reservoir, may deposit when the thermodynamic conditions of the temperature, pressure or composition changes in the process of production. Deposition of solid elemental sulfur may block the pores in the formation and significantly affect the gas deliverability. In this paper, sulfur deposition mechanism is analyzed in the reservoirs. Based on the characteristics of sulfur deposition in the formation, a corrected function is introduced to modify the gas flow. Then, an evaluation method of the effect of sulfur deposition on gas deliverability is presented. For a practical sour gas reservoir, the gas deliverability considering sulfur deposition in formation is calculated and evaluated. The results show that the decrease degree of gas deliverability is different and it depends on the physical parameters in the formation on which the gas well is located.