bluuebunny/crossref_metadata_2025_split huggingface dataset:
Automatic Well Testing and PIP Calculations Using Smart Rod Pump Controllers
Authors: Ibrahim Ahmed Mohamed Fouad , Sadek Nael Nabil 
Published: February 2012

ABSTRACTWorldwide, as conventional oil resources are depleted, beam pumping system is becoming the most common type of artificial lift methods for onshore wells. Production testing of beam pumped wells is an important diagnostic tool to detect potential production problems and for monitoring reservoir performance. In addition, well test data and the Inflow Performance Relationship (IPR) combined with the production data help to design, analyze and optimize the whole well production system. With the growing number of beam pumped wells, the value of such data is increasing over time.Published literature and field experience show that the traditional well testing methods for beam pumped wells have various limitations such as being hazardous, have a lot of assumptions, provide only a snapshot data and are costly processes. On the other hand, well testing is problematic if the wells are isolated or at a far distance from the field facilities. Also when large population of beam pumping wells are connected to central batteries, it is difficult to determine the daily production of each well or to identify the cause of low production in the battery, as there is not an easy way to identify which well is affected.This paper will discuss a technology that started to replace traditional well testing facilities or at a minimum a new way to verify individual well performance on a day by day basis. The new method continuously infers the production and calculates the corresponding bottom-hole pressure using a smart rod pump controller system located at the well site by analyzing the downhole pump card data. The basic logical assumptions and methodology of the new method are summarized to give an understanding of how the test is implemented and under what conditions the test will be accurate. Real field data are shown and compared with data acquired by other traditional methods.
The Impact of Pore Geometry Aspects on Porosity-Permeability Relationship - A Critical Review to Evaluate NMR Estimated Permeability
Authors: Salah Ahmed 
Published: February 2012

AbstractThe permeability prediction is of extreme importance in hydrocarbon reservoir management. The reservoir rocks are made up of grains, cement and pore network. The pore network is made up of larger spaces, referred to as pores, which are connected by small spaces referred to as throats. The pore spaces control the amount of porosity, while the pore throats control the movement of fluids and the quantity of rock permeability.The core analysis data for 219 sandstone and limestone samples were available. The data include porosity, permeability and capillary pressure by mercury injection. These samples represent 21 stratigraphic units. The geologic age varied between Cretaceous and Pliocene. Sandstone reservoirs are represented by 179 samples, while 40 samples represent carbonate reservoirs. The data were collected from different geographic areas within Egypt.Pore-throat size distribution parameters were calculated from the data of capillary pressure. These data were used to approximate the distribution of pore volume accessible by throat of a given effective size. A new definition for micro-porosity was proposed based on pore throat size distribution. These data was used to descriminate the sample porosity into micro and macro porosity based on a pore throat cutoff, which was determined from the relationship between storage and flow capacity of the pore network. The relationship between permeability and aspects of pore geometry; micro-porosity, macro-porosity and pore throat parameters have been analyzed and discussed.The interpretation of the results indicates that the permeability is mainly a function of pore-throat size distribution while the amount of the porosity or the porosity configuration is not the main factor that controls the amount of permeability. A new model for permeability prediction was develpoed which incorporate the pore space and pore throat. The obtained results have shown the great influence of pore throat on permeability prediction.
Advance Lifting Technology for Continuous Reservoir Monitoring and Production Optimization in Real Time – Aghar 04 Pilot Project Case Studies
Authors: Sabaa Ahmed , Crema Giordano , Soegiyono Rini 
Published: February 2012

Abstract
Permanent Downhole Gauges (PDG) can play great roles in production optimization as well as reservoir continuous monitoring and management. Data obtained from these gauges or sensors can give useful information to applications, including but not limited to monitoring artificial lift performance, pressure monitoring, transient well testing, and evaluation of well performance. Reservoir continuous monitoring, production losses mitigation, pump optimization and benefits from detection or prevention to early failure have been considered overcoming short-term concerns about cost containment during economic downturn.
This paper presents case studies based on a pilot project deployed by Agiba Petroleum Company and Schlumberger in Aghar-4 field, Western Desert, Egypt. This field consists of three producers that are equipped with permanent downhole gauge and integrated real time system connecting bottom hole sensor technology to some essential surface measurement capability.
Aghar-4 is a promising heavy oil field with a total of 13 wells drilled and being produced by sucker rod pumping to the date of the study. Aghar 4-1 was commissioned in January 2009 and is the first well in the Middle East operating with the intelligent downhole monitoring system application. This success story in Aghar 4-1 implied the installation of two more systems in Aghar 4-4 and Aghar 4-12. Later in October 2009, Aghar 4-12 made its history as the first world sucker rod well integrating downhole sensor, surface controller, and real time PC web-based satellite transmitted interface monitoring system.
Artificial lift downhole equipment failures often occur within a relatively short period causing reduced or deferred production. Continuous real time monitoring of the environment in and around pumps will significantly improve production through a proactive surveillance and optimization of artificial lift operations.
How to Measure the Correlation between Return of Oil Production Projects Realistically?
Authors: Costa Lima G. A. , Gaspar Ravagnani A. T. , Schiozer D. J. 
Published: February 2012

Abstract
The use of portfolio theory has been appointed as an important tool for economic risk management in the O&G industry. There are only 3 input parameters: (a) mean return; (b) standard deviation of return; (c) correlation between pairs of assets, projects, prospects, etc. Although simple, one practical problem with the application of this model is the estimation of correlation because there is no historical data as in the case of financial assets.
This paper presents a methodology for the estimation of linear and rank correlation between E&P oil and gas projects through the following steps: 1) Estimate the mean and risk of each project; 2) Identify the variables that are common to two projects such as oil price, fiscal regime, etc; 3) Simulate the return of each project; 4) Estimate the correlation between projects.
This model is applied to estimate the mean and risk of a portfolio of 3 projects typical from the deep-water in Brazil with reserves of 346, 629 and 694 million barrels. The fiscal model is based on Tax & Royalty. For all these projects, production strategy and production curve come from reservoir simulation.
Alternatively, correlation between return of projects is assumed subjectively (a typical number is 70%) but with this model it can be estimated in a much more sound way. Results indicate that main determinants of correlation are fixed cost, variable cost and oil quality. With this information, managers are able to select best portfolios – for example, by means of farm-in and farm-out – in order to create value for stakeholders considering not only means, but also risk and possible benefits from diversification.
Synchronization of Coiled Tubing Drilling (CTD) in Extended Reach Drilling (ERD)
Authors: Alimuddin Sultan , Shah Nihar , Das Abhirup , Kumar Neeraj , Pandey Ankit , Abhishek Kumar 
Published: February 2012

Abstract
Coiled tubing is used for a range of oil and gas well operations. It is mainly used in drilling, work over, pumping, logging etc. This technology is becoming an economic substitute to conventional drilling as it is highly cost and time saving. Drilling with Coiled tubing allows incessant supply of the pipe into the hole without constant interruptions, whether it can be as a drill string or tubing. Nowadays, most of the wells drilled are deviated because oil & gas reservoirs can be exploited more efficiently through extended horizontal wells. Also, Extended reach drilling make economic as well as environmental sense by reaching different pockets without drilling lots of wells. Through ERD we can also construct multiple wells to drain a large area from a single surface location. Moreover, the reserve situated in a populated area and geographically harsh area can be thoroughly exploited using high angle extended reach deviated and horizontal well.
However in drilling high angle deviated and horizontal wells with coiled tubing, the motion of coiled tubing drilling is somehow restricted due to generation of high friction forces which lead to buckling inside the well. Another challenge using CTD for ERD is effective transport of drilled cuttings, as the complete string is in sliding mode while drilling. Apart from this there many challenges which drilling industry is facing in CTD usage with ERD.
The main aim of this paper is to synchronize CTD usage with ERDs. Here we have presented the benefits & challenges of CTD-ERD system which can be used to save time and cost as well as proposing the possible current solutions. Knowing the limits and appropriate usage of coiled tubing in ERDs will save lot of costs and has potential to revolutionize the existing drilling activity of whole exploration, production and geothermal sectors.
A New Transformation for the Rapid Solution of the Rachford-Rice Equation in Phase Split Calculations
Authors: Gaganis Vassilis , Varotsis Nikos 
Published: February 2012

AbstractThe Rachford-Rice equation needs to be solved during phase split calculations required in several petroleum engineering applications such as reservoir simulation, determination of minimum miscible pressure, pipeline flow, etc. This calculation often has to be repeated for every discretization block and for every time step, thus claiming a significant fraction of the total computation time (CPU). Existing techniques exhibit a fairly poor performance when a bubble of a very light composition or a droplet of a very heavy one is present in the mixture. As the computation time in parallel computing implementations is determined by the slowest grid block calculation, this latency bears a huge impact on the total required CPU time.In this work, a transformation of the conventional Rachford-Rice function is proposed with which the original equation is rewritten as a function of a single hyperbolic term instead of the vapor fraction. The transformed function is monotonic and strictly concave and can be fitted by low order rational model functions. A novel algorithm, which is able to fit such rational model functions and does not require the calculation of a derivative, is proposed instead of the Newton-Raphson straight line. The root of these functions is obtained directly by performing simple computations and is utilized as the next estimation.The proposed method converges rapidly, as it requires only a single function evaluation at each iteration even in the case of negative flash or near-critical calculations. Every single estimate lies within the valid vapor fraction range thus ensuring robustness without the need for utilizing bracketing. Several test cases demonstrate an excellent performance compared to the existing methods hence leading to a robust solution and substantial CPU time savings.
A New Emulsified Acid to Stimulate Deep Wells In Carbonate Reservoirs: Coreflood and Acid Reaction Studies
Authors: Sayed M. A. , Nasr-El-Din H. A. , Zhou J.. , Zhang L.. , Holt S.. 
Published: February 2012

Abstract
Acid treatments in high temperature deep wells drilled in carbonate reservoirs represent a challenge to the oil industry. The high temperature of deep wells requires a special formulation of emulsified acid that can be stable and effective at such high temperatures. At these high temperatures, both the reaction rate between acid and rock, and corrosion rate of tubulars are high. This fact makes protection of tubulars and reducing the reaction rate between rock and acid challenging.
A new emulsifier was used to prepare emulsified acids that can be used in stimulating deep wells drilled in carbonate reservoirs. All emulsified acid systems were formulated at 0.7 acid volume fraction, and the final HCl concentration was 15 wt%. A coreflood study was conducted in order to study the efficiency of the new emulsified acid to create wormholes, and to increase the efficiency of the stimulation treatment. Both low and high permeability Indiana limestone cores were used in the present study. The effect of acid injection rate, rock permeability, and emulsifier concentration on the performance of emulsified acid systems were studied. The reaction between emulsified acid and limestone rocks was studied using a rotating disk apparatus at 230 ºF, and rotational speeds up to 1,500 rpm.
The results showed, for both low and high permeability Indiana limestone cores, the new emulsified acid system created deep wormholes at all injection rates (0.5 to 10 cm3/min), with no face dissolution encountered during acid injection. The reaction rate between the new emulsified acid and limestone cores was measured using a rotating disk at 230 ºF. The dissolution rate increased as the rotational speed increased, indicating that reaction between emulsified acid and limestone is a mass transfer limited reaction. Both reaction rate and diffusion rate decreased as the emulsifier concentration increased from 0.5 to 2.0 vol%. From these results, the new emulsifier can be used in formulating emulsified acid systems that can be used effectively in stimulation of high temperature deep wells. This paper summarizes the results of testing the new emulsified system, and recommends its use for field application in deep carbonate reservoirs.
Evaluating the Severity of Dents in Pipelines
Authors: Popineau D.. , Wiet P.. 
Published: February 2012

Abstract
Some years ago, after several pipeline accidents, the oil industry invited work groups to investigate the subject of predicting the burst pressures of damaged pipelines. Several damage evaluation guidelines were produced as a result, but these remained conservative in approach and, above all, were applicable only to minor damage.
Total, however, having observed far more serious damages on offshore pipelines, wished to go further and, in 2006, initiated a specific study as part of the "Deep Offshore Development", internal R&D project.
This cross-functional work permitted in 2011 the realisation of a finite element analysis model, EMPREINTE. This application has three objectives: to model pipeline dents, calculate the pipeline ultimate burst resistance and deduce a working pressure that includes an appropriate safety factor.
To evaluate damage to pipelines, this application uses an innovative approach: from the measured damage, it recreates the shape of the object that produced the observed dent, then simulates the damage by calculation and finally predicts the rupture pressure.
The method was validated by a series of burst tests on pipes on which dent-type damage (some extending to more than 50% of the pipeline diameter) had been inflicted and metal loss deliberately induced.
The software application was used in real conditions for the first time when an explosion damaged an HP gas pipeline feeding an LNG plant. Where strict application of the damage evaluation codes dictated the conservative course of replacing the damaged section, EMPREINTE confirmed that the repair could be postponed. The plant's production was therefore quickly resumed, minimizing LNG production losses (which might have attained several millions of USD if the damaged section had been replaced immediately).
Flow Structure Development Due to Injection Water into the Annulus of Heavy Oil Pipe Flow
Authors: Sakr Ahmed L. , Sultan G. I. , Safan M. G. , Tolba M. M. 
Published: February 2012

Abstract
This work investigates the flow structure development due to injecting water into the annulus of heavy oil pipe flow. Numerical simulation of the axisymmetric core annular turbulent flow is carried out using the standard k–ω model. The flow field and flow characteristics are investigated using FLUENT 6.3.26. The core annular flow of heavy oils-water in 15.24 cm diameter pipe, with three core diameters is considered. The influence of flow parameters upon the development of axial and radial velocity, turbulent kinetic energy, turbulent intensity, and strain rate profiles are investigated.
Results show that flow development depends on the core to outer diameters ratio, oil viscosity, flow velocity, and water loading ratio. As oil's viscosity increases, flow structure develops faster towards fully developed one. Fully developed velocity profiles show uniform distribution in oil's core, while all velocity changes occur in water flowing in pipe annulus. The flow in the core region seems to be as rigid body carried by annular water flow. It has been demonstrated that major changes in flow structure occur at the oil-water interface.
A New Approach Formation Tester Interval Pressure Transient Test Design
Authors: Tellapaneni Prasanna K , Shukla Sourabh , Jackson Richard R , Dixit Harshad 
Published: February 2012

Abstract
Increased deepwater drilling today requires that expensive and risky drillstem testing operations be optimized by other technologies that provide dynamic information about the formations to be tested. Wireline-conveyed interval pressure transient tests (IPTTs) are becoming a common practise today for optimizing and designing these expensive tests.
Typically, prior to an IPTT, there is only a limited amount of information available about the reservoir and fluids properties and it tends to be generally probabilistic. Therefore, the optimal design of IPTT tests is a necessary challenge for a successful and reliable test. IPTT is found to be dependent on the noise and on observable flow regimes associated with the pressure buildups. Success and reliability are not only a function of gauge metrology but also of the formation deliverability and geometry.
This paper describes a new methodology for IPTT design that allows estimation of the reliability of these transient tests. A normally distributed random noise is superimposed on the analytical pressure profile computed for a given formation, fluid PVT properties, and gauge metrology. The success of an IPTT in a particular environment is estimated based on the theoretical pressure derivative and noise-superimposed pressure derivative. This approach is repeated for a range of rock, and fluid properties and practical limits to identify what is a successful. Two field examples are presented to validate this methodology.
Study of Residual Oil in Tahe 4th Block Karstic/Fractured Heavy Oil Reservoir
Authors: Zhongchun Liu , Jirui Hou , Jianglong Li , Qian Cheng 
Published: February 2012

Abstract
Tahe 4th block karstic/fractured Heavy Oil Reservoir is a block bottom water reservoir with the greater heterogeneity. By the end of 2009, the yearly rate oil production is 7.23×106tons, and the oil recovery efficiency is 11.4%. But after a long period of development, many deficiencies of fast producing are exposed gradually: the water breaks through early in the oil wells, the water cut increase fast; the natural decline rate is high, and the development degree of the reservoir is lower.
By physical simulation experiments, the residual oil types and their effect factors have been investigated. The five main residual oil types in karstic/fractured reservoir have been determined. Furthermore, according to the dynamic and static information of wells, the production wells have been divided into three types by clustering method. And the 4th block of Tahe oil field have been divided into three zones in accordance with the well types, including a zone with a lot of caves, a zone with caves and fractures and a zone with fractures. Meanwhile, the main residual oil types and the research direction of EOR technologies in different zones have been pointed out.
The knowledge gained from this study can be a foundation to increase the well controllability and improve oil recovery in fractured/karstic carbonate reservoirs.
Design and Application of Drilling Fluids for HPHT Well - A Case Study of Mafia Field
Authors: Oriji A. B. , Dosunmu A.. 
Published: February 2012

Abstract
It is very important to design a stable mud system for any detailed drilling programs. Application of the best practices and well planned engineering field execution is critical in drilling and completing HPHT wells in a cost effective manner and minimal operational problems. Conventional mud designs and test equipment fell short of addressing the inherent problems associated with HPHT wells. In this study, the conventional practices in mud design were reviewed and advances in design for best practices developed for Mafia field. Many of the conventional practices were actually found to be inadequate for HPHT drilling. This paper present techniques on determining and applying mud properties at HPHT deep wells through a rigorous laboratory test and mathematical equations to generate detailed engineering guidelines for HPHT drilling fluid. Water based mud were formulated with special additives at temperature between 250-500°F and 5,000-10,000 psi to check for its stability under such elevated temperature and pressure. A standard temperature concept used for controlling the surface mud weight was defined. With the actual field results from the Mafia field, model equations were developed and the sensitivity analysis done to show the relative influence of pressure and temperature on the drilling fluids using the spider and tornado plots. The model equations derived from the multiple regression analysis were used to predict and rank the best rheological properties for the field, thereby saving the time and rigors associated with laboratory experiments.