bluuebunny/crossref_metadata_2025 huggingface dataset:
Modeling of Pigging Operations
Authors: Lima P. C. R. , Yeung H.
Published: December 2007

More and more transient gas-liquid operations in pipes has been successfully applied in the oil and gas industry. Pigging operation in two-phase pipelines to remove liquid accumulation or for cleaning purpose is an important transient operation. Another important operation is the injection of gas to transport the accumulated liquid in the pipeline to process facilities. Analysis of such transient two-phase flow in a pipeline is necessary not only for designing the liquid and gas handling facilities, but also for safe operating procedure. In pipeline-riser system such operations cause even more severe change in flow conditions. A two-fluid model has been developed to determine the transient behavior of fluids during these operations. The derived one-dimensional set of equations for each flow pattern describe the flow of fluids in all regions. Semi-implicit finite difference schemes were used to solve the initial and boundary value problem for each phase of the pigging process: gas/pig injection, gas shut-in, slug production and gas flow out of the system. An extensive experimental program has been carried out to acquire two-phase transient flow and pigging data on a 67 m long, 2 in diameter pipeline-riser system. A computer based data acquisition system has been utilized to obtains rapidly changing and detailed information of the flow behavior during the transient tests. The model compares well with the experimental data for characteristics such as inlet pressure, hold-up and pig velocity.
Variable Wellbore Storage Models for a Dual-Volume Wellbore
Authors: Spivey J. P. , Lee W. J.
Published: December 2007

Two new composite, or dual-volume, wellbore models are presented. Both models describe a two-compartment wellbore coupled through a pseudosteady-state flow equation. The models differ in how the wellbore is coupled to the reservoir.

The first model describes the pressure response in a well with a "leaky packer". This model may exhibit two unit-slope lines during wellbore storage, one at earliest times corresponding to the volume of the tubing, and a second one corresponding to the volume of the tubing plus the tubing-casing annulus.

Gringarten noted that apparent wellbore storage coefficients for naturally fractured reservoirs are often one or two orders of magnitude higher than calculated from wellbore geometry, and attributed this effect to storage in natural fractures intersecting the wellbore.1 The second, "near-wellbore fracture storage," model accounts for storage in the fracture system intersecting the wellbore, completion damage, and storage in the wellbore proper.

Both models give pressure responses that are very similar to those exhibited by the model proposed by Fair to describe phase segregation and thermal effects.2,3 This may explain the success of the Fair model in modeling many situations in which neither phase segregation nor thermal effects are likely to occur.

The "near-wellbore fracture storage" model also gives a pressure response that is almost identical to that exhibited by a pseudosteady-state dual porosity reservoir with wellbore storage. Gringarten observed that a majority of tests in fractured reservoirs appear to exhibit pseudosteady-state rather than transient dual porosity behavior.1 The proposed "near-wellbore fracture storage" model may account for the behavior interpreted as pseudosteady state dual porosity in many of these cases.
StarWars Laser Technology for Gas Drilling and Completions in the 21st Century
Authors: O'Brien D. G. , Graves R. M. , O'Brien E. A.
Published: December 2007

This paper describes results of the second phase of a GasResearch Institute (GRI) funded research program. Theoverall purpose of this research is to advance a fundamentalchange in the methods currently used to drill and completenatural gas wells applying the U.S. Defense Department'sStarWars laser technology. Results of tests conducted at theU.S. Air Force's high power laser research facilities arepresented. This phase of the research has used the ChemicalOxygen-Iodine Laser (COIL) high-powered laser invented bythe U.S. Air Force in 1977 for air-to-air defense. Located bof[b-dghj-npqrsvwxyz] U.S. Air Force Research Laboratory's Directed EnergyDirectorate, Kirtland Air Force Base, New Mexico, COIL hasgained notoriety as an airborne laser tactical weapon capableof tracking and destroying missiles. More than 100 rocksamples – including sandstones, limestones, shales, salt, granites and concrete – were exposed to laser beams ofvarying power and duration. The results were encouraging inthat the laser was able to penetrate all rock types. Samplessaturated with water, brine, oil and gas were also tested tomore accurately simulate the downhole drilling environment.The effects of vapor interference, gas atmosphere, confiningrock stresses and operating the laser in continuous andchopped modes will be discussed.

The basic research conducted on laser-rock-fluidinteractions is helping provide the foundation on which todetermine the benefits of using StarWars laser technology fordrilling and completing natural gas wells.
Influence of Drillpipe Rotation and Eccentricity on Pressure Drop over Borehole during Drilling
Authors: Ooms G. , Burgerscentrum J. M. , Kampman-Reinhartz B. E.
Published: December 2007

Field measurements have revealed that the pressure drop over a borehole during drilling of a slim oil well or a well with a long reach can depend significantly on the rotation speed of the drill pipe. This paper discusses analytical, numerical and experimental studies to explain this effect. Special attention is paid to the inertial forces in the liquid in the annulus caused by the rotation and eccentricity of the drill pipe. It is concluded that for large values of these inertial forces the axial pressure drop depends indeed significantly on the rotation speed of the drill pipe. A pressure drop simulator has been developed that includes this effect, and that is in good agreement with field test data.
Sucker-Rod-Pumping Failures in the Permian Basin
Authors: Heinze L. R. , Ge Z. , Rahman M. M.
Published: December 2007

Sucker rod pumping is the most popular form of artificial lift in the Permian Basin, which is one of the largest petroleum production basins in the United States.This paper is part of the research results of the Artificial Lift Energy Optimization Consortium (ALEOC),a research project which is sponsored by 11 oil companies operating in the Permian Basin.The analyzed data provided by these 11 oil companies came from more the 25,000 sucker rod pumping wells, a quarter of the total sucker rod pumped wells.The wells' locations are scattered in the Permian Basin. Therefore the information presented here is typical enough of this area. This paper presented the methods used to organize and pre-treat the primary databases provided by the operators, and the techniques used to analyze the failure data. Failure frequency was introduced to do comparisons, plots according to failure frequency, year, company, area location, and formation were given to make the data more straightforward. Analysis of results show that different companies have very different operation management and data manipulation methods, which made it necessary for companies to come together to learn from each other. There are big differences among the failure frequencies of companies, which is an indicator of their field operation efficiency, facility manipulation underground working conditions of the sucker rod pumping equipment and so forth. There is a trend of yearly failure frequency decrease among the participated companies with a few exceptions; pump failure frequency is the largest problem among those of the sucker rod pumping components. The results present a picture of sucker rod pumping in the Permian Basin and can be used in further statistical analysis of the sucker rod pumping failures and to guide later decision-making.
Coiled Tubing Used as a Continuous Sucker-Rod System in Slim Holes: Successful Field Experience
Authors: Solanet Fernando , Paz Luis , Leniek Humberto
Published: December 2007

The need of cutting the costs of new oil wells in the San Jorge Basin led YPF S.A. to study the option of reducing well diameters. For an effective cost reduction, it was necessary to be able to case the hole with diameters smaller than 4.5 inches.The problem of a completion in 3.5 inches or less was the inability to efficiently lift the production with traditional methods.Initially a monobore type completion was tested, in detriment of pump setting depth and pump efficiency due to the presence of gas.

The introduction of a mechanical pumping system lifting fluids through coiled tubing made possible the solution of the problems of the pump depth and efficiency. The paper describes the type of installation and procedure followed to run the system.

The success of this type of installation will allow the operator to produce in wells cased with 3.5 inches or less, matching the efficiency of conventional wells cased with 5.5 inches, in a range of production volumes compatible with most of the wells in the basin. At the same time, the system offers the advantage of using conventional technology such as beam pump on the surface and mechanical pump at the bottom of the well.
Conditioning 3D Stochastic Channels to Pressure Data
Authors: Bi Zhuoxin , Oliver D. S. , Reynolds A. C.
Published: December 2007

This work discusses the development and implementation of a procedure to condition a stochastic channel to well- test pressure data and well observations of the channel thickness and the depth of the top of the channel. The stochastic channel is defined by a set of geometric random variables (referred to as geometric model parameters) that describe the location, size and shape. Channel and non- channel permeability and porosity are treated as random variables. These four random variables plus the geomet- ric parameters comprise the complete set of model param- eters. Multiple conditional realizations of the geometric parameters and rock properties are generated to evaluate the uncertainty in model parameters and the reduction in uncertainty obtained by conditioning to well-test pressure data.
Analytical Solutions for Productivity Evaluation of Multifractured Wells in Multilayered and Bounded Reservoirs
Authors: Basquet R. , Alabert F. , Caltagirone J -P.
Published: December 2007

We propose a semi-analytical model to represent the transient and pseudo-steady state behavior of hydraulic fractures in multilayered reservoirs where cross-flow is permitted between layers. Fractures can be horizontal or vertical. We only consider vertical fractures which are parallel to x or y axes. Fractures are fully or partially penetrating in the formation and can extend across several layers. We consider single or multiple fractures where influence between each other is modeled. The reservoir is bounded by plane surface perpendicular to the main axes, and we can impose on these limits either no-flow, constant pressure or mixed boundary conditions.

The solutions are obtained from plane (zero thickness) source solutions developed in the Laplace-Fourier domain. Basquet et al.1 already used this method for the determination of point source solutions, the reasoning is still based on the « quadripole » method to account for layer cross-flow and on the Fourier transform to describe boundary effects. Vertical line source solutions are developed and are then integrated over the horizontal fracture extension to obtain the plane source solution under the assumption of uniform flux solution. The infinite conductivity solution is obtained by splitting the fractures into basic slabs with uniform flux and solving a linear system.

The solution is validated against existing analytical solutions (using concept of instantaneous sources and Green's functions) modeling vertical or horizontal fractures in single layer reservoir. To check that the cross-flow between layers is well represented, we compared our vertical line source transient solution versus well known analytical solutions in multilayered reservoirs.
Innovations in Global Electronic Data Delivery
Authors: Murchie S. , Provost J. T. , Burke T. , Karr G. , Alam S. O. , Scheibner D. , Citerne A.
Published: December 2007

New techniques and technologies have been developed and assembled to create a global electronic data delivery framework that is robust, secure and efficient. This framework serves any data type throughout its life span—as it is acquired, processed and archived—and provides the means for it to be transmitted and intrinsically integrated into the end user's domain. Details of the data delivery framework and its overall scope will be given, followed by a number of geographically distinct, tailored applications of the technology.

The advancing technology front has resulted in an explosion in data volume, of which an ever-increasing amount is digital. In the midst of this explosion, the need for the highest quality data to be efficiently and electronically delivered to its various destinations has remained a goal. The solution presented herein combines an enhanced mechanism for electronic data delivery with tools that improve data usability, storage and management. All the while the data adhere to the exploration and production (E&P) standards.

This framework is being applied today to formation evaluation data, such as wireline and logging-while-drilling data. However, it will soon expand to encompass all forms of data produced within the E&P industry. As the industry rapidly assimilates advances in electronic communications to improve operations efficiency, its decision-makers are demanding drilling and formation evaluation data on their desktops in real time.

This paper outlines significant contributions in the areas of data security and transmission reliability, capitalizing on established and expanding networks (Internet, intranet), data composition and management techniques, and the development of software applications to facilitate end-user data reception, handling and manipulation.
Reducing Uncertainties in Production Forecasts by Constraining Geological Modeling to Dynamic Data
Authors: Hu L. Y. , Le Ravalec M. , Blanc G. , Roggero F. , Noetinger B. , Haas A. , Corre B.
Published: December 2007

Building reservoir geological models that are consistent with all available information is necessary to reduce uncertainties in production forecasts. The stochastic/geostatistical approach is the only feasible way of integrating all kinds of data ranging from the geological knowledge to the production history. A stochastic model is chosen that accounts for geological knowledge, and geostatistical simulation provides realizations of the stochastic model. These realizations can be conditioned to static data at well locations to reduce the model uncertainty in the area where data are available.

All along the different stages of a field life more and more dynamic data are available. This paper addresses the issue of generating model realizations that account for available dynamic data to further reduce uncertainty in the underlying geological model. A general tool has been developed to build geostatistical realizations that match both the available geological and dynamic data. The core of this tool is the Gradual Deformation Method that allows consistent modification of a realization in a continuous way. This method can be combined with a nonlinear optimization method for constraining realizations of a stochastic model to dynamic data. This approach is operational for Gaussian or non- Gaussian pixel based models. Model realizations can be deformed globally or locally while preserving the geostatistical characteristics. Several examples are provided to illustrate different features of the gradual deformation approach.
Extrapolation of Laboratory Measured Black Oil and Solution Gas Fluid Properties for Variable Bubblepoint Simulation
Authors: McCain W. D. , Spivey J. P.
Published: December 2007

Reservoir simulation of variable bubblepoint processes such as water or gas injection into black oil reservoirs often requires extrapolation of reservoir fluid properties to pressures above original bubblepoint pressure. This has been known for over twenty years; however, to date, no rational and consistent procedure for these extrapolations has been proposed.

We propose a scheme to extrapolate solution gas-oil ratios and the corresponding oil formation volume factors, oil viscosities, and oil densities, which preserves the correct relationship of these properties to pressure. The procedure is based on empirical observation that the relationship between solution gas-oil ratio and oil formation volume factor is linear and that oil viscosity and oil density have a linear relationship in the pressure range of interest. A material balance equation is used to connect the quantities and properties of the surface fluids, oil formation volume factor, and solution gas-oil ratio to the density of the reservoir oil. Thus, the four properties can be extrapolated together in an empirically and theoretically based process.

A similar scheme is used to extrapolate the properties of the solution gas, forcing the correct shapes of gas z-factor, gas formation volume factor, and gas density as functions of pressure. Gas viscosity, as usual, is calculated with a correlation.

After extrapolation, the consistencies of these oil and gas properties are checked by ensuring that total compressibility remains positive throughout the range of extrapolated pressure. Thus, a rational procedure based on known empirical and theoretical relationships among these fluid properties is now available for use in preparing fluid properties for reservoir simulation when the possibility of variable bubblepoints exists.

The application of these relationships to quickly extrapolate values of these seven fluid properties is demonstrated using an interactive graphical spreadsheet.
An Efficient Finite Difference Model For Flow In a Reservoir With Multiple Length-Scale Fractures
Authors: Lee S. H. , Jensen C. L. , Lough M. F.
Published: December 2007

We describe a hierarchical approach for modeling fluid flow in a naturally fractured reservoir with multiple length-scale fractures. Based on fracture length (lf) relative to the finite-difference grid size (lg), fractures are classified as belonging to one of three groups: (1) short disconnected fractures (lf << lg), (2) medium-length fractures (lf ~ lg), and (3) long fractures (lf << lg). Effective grid-block permeabilities, associated with the short and medium length fractures, are used as input to a finite-difference simulator. We also present a separate transport equation for flow through long fractures to capture effects of large-scale high permeability pathways. Our new approach provides an improved means to include realistic and explicit fracture descriptions.

Previously, Lough et al. (1997, 1998) developed a numerical method to compute the effective permeability of simulation grid-blocks with realistic fracture characterizations. Although this method handles generalized fracture geometries, it is numerically inefficient for the case where many small fractures exist. The method can also underestimate the flow contribution from long fractures. Assuming a linear potential gradient alongthe short fractures, we derive an analytical solution for the permeability contribution from short fractures. The solution becomes more accurate as fractures become randomly distributed and asymptotically small in length. The permeabilities from this analytical solution are used as the effective matrix permeability in computing a combined effective grid-block permeability that includes medium-length fractures. The method of Lough is used for this computation. This hierarchical approach takes into account coupled flow between the rock matrix, short fractures and medium-length fractures. Long fractures are modeled explicitly in the reservoir simulator, using a transport equation that describes flow between long fractures and surrounding simulation grid-blocks.

Simulation results from our new hierarchical approach are compared with those from the conventional dual porosity/permeability model. Numerical efficiency and accuracy are also examined.
Application of a New Model to Analyze Leakoff Tests
Authors: Altun G. , Langlinais J. , Bourgoyne A. T.
Published: December 2007

A leak-off test (LOT), commonly known as formation pressure integrity test (PIT), is a verification method to estimate the fracture pressure of exposed formations. After cementing each casing string, a LOT is run to verify that the casing seat can withstand the wellbore pressure required to safely drill to the next casing setting depth. Fracture pressure determined from the test is used as the maximum pressure that may be imposed on that formation. Critical drilling decisions for subsequent casing setting depths are based upon the result of a LOT. Accurate formation fracture gradient determination is critically important.

Although a LOT is a simple and inexpensive test, its interpretation is not always easy, particularly in formations that give non-linear relationships between the pumped volume and the observed pump pressure. Ideally, a straight-line relationship of pump pressure to volume pumped is obtained that reflects primarily the total system compressibility, i.e., the compressibility of the drilling fluid, casing expansion, and wellbore expansion. Non-linear LOT behavior is thought to be caused by gas in the system, by borehole failure, or by leakage of drilling fluid into the cemented casing/borehole annulus. There is, however, no mathematical model explaining the non-linear LOT behavior. Disagreement on determining or interpreting actual leak-off pressure from the test data among the operators is common, especially for shallow formations.

In this study, a mathematical model is derived to assist in the analysis of non-linear LOT behavior. The model has been used to predict the observed non-linear behavior of field examples. In the case of a non-linear LOT, the model has also been used to predict the maximum fracture pressure of the formation without running a test until formation fracture.
Low Field NMR-Tool for Bitumen Sands Characterization: A New Approach
Authors: Mirotchnik K. D. , Allsopp K. , Kantzas A. , Curwen D. , Badry R.
Published: December 2007

NMR well logging technology has become a recognised and effective method for characterising hydrocarbons in porous media. Many recent publications have attested to its suitability for this purpose. NMR can be used to determine porosity, permeability and viscosity in situ, to estimate pore size distribution, to indicate wettability alteration during the recovery process and to determine many other important parameters. All previous NMR applications were developed for investigating conventional oil reservoirs. Extending the detection capabilities of NMR Logging tools into heavy oil and bitumen reservoirs for in situ characterisation is very important for oil producers in the Province of Alberta, Canada and other heavy oil and bitumen areas (Venezuela, California, Russia, etc.). The main problem encountered when trying to use NMR technology to evaluate these reservoirs is that the relaxation characteristics of heavy oils and bitumen are at the limits of the logging tools’ detection capabilities.

The NMR signal obtained from conventional oil, heavy oil and bitumen formations can consist of both hydrocarbon signal and water signal. Each NMR signal can further characterise both mobile and immobile fluids in the porous media. However, as the viscosity of the hydrocarbon phase increases and the NMR signal shifts towards lower relaxation times, the composite NMR signal for the hydrocarbon bearing formation becomes very complicated. As the viscosity of the bitumen exceeds 100,000 cP (at natural conditions), the relaxation characteristics of bitumen become partially non-detectable by both the logging and laboratory NMR tools. As a result, the conventional methods of NMR detection fail to recognise precisely the hydrocarbon components.

Laboratory NMR measurements of bitumen bearing porous media under different temperatures were performed. This method delivered new information about bitumen reserves in situ. The results show that low field NMR holds promise for the characterisation of heavy oil and bitumen recoverable reserves. This new approach can be applicable for real time monitoring of thermal extraction including monitoring the efficiency of thermal recovery methods.
Waxy Crude Oil Restart: Mechanical Properties of Gelled Oils
Authors: Hénaut I. , Vincké O. , Brucy F.
Published: December 2007

In case of a prolonged shutdown and an inopportune cooling, the crystallization of a crude oil takes place and hinders the production of these petroleum products. Because of the gel-like network formed by the crystals entrapping the oil, a restarting pressure is required to start-up flow. In order to predict the necessary pressure, the restart process and the corresponding mechanical behavior of the gelled oil must be assessed. In this paper, a set of two experimental approaches is presented and discussed in relationship with the restart process. The solid-like behavior of the gelled bulk oil was investigated thanks to a set of mechanical test cells. The rheological behavior of the gelled waxy crude oil was studied with a vane test apparatus and a controlled-stress rheometer. Eventually, the two experimental methods gave complementary and converging results revealing how a crude oil stuck inside a pipeline would react during a restarting operation. They help the understanding of the physical mechanism of the flow restart and release the data required for prediction.
An Evaluation of Simulation Techniques for Modelling Squeeze Treatments
Authors: Mackay E. J. , Sorbie K. S.
Published: December 2007

Modelling scale inhibitor squeeze treatments is taking on an expanding role, partially due to the increasing complexity of systems that need to be treated against scale formation, and partially due to the improved accessibility of codes capable of modelling these treatments. Five such codes have been identified, ranging from near wellbore single-phase models designed with inhibitor squeeze treatments specifically in mind, to full field, fluid, thermal and chemical transport simulators. The former type of model is routinely used by production engineers to optimise squeeze treatments. The later is a tool that can be used in a research environment for improved understanding of various aspects of squeeze application, or to study specific cases that are exceptionally problematic. The risks associated with horizontal wells in particular, partly due to their cost, and partly due to the potential losses from deferred oil, mean that modelling is often seen as a useful tool in reducing uncertainties.

The choice has to be made between the requirement for accurate flow calculations and chemical modelling, and the need to set up models quickly and accurately. Guidelines are presented to assist in the choice of code. These guidelines are accompanied by case studies that demonstrate the scenarios in which the different models might be used. At one end of the spectrum, the simpler models can be used to optimise squeeze treatments in quite complicated systems, provided good fluid flow data are available, and it is known that the assumptions made are valid. At the other extreme, cases are presented that show the application of field models in investigating issues such as the impact on squeeze life of formation cooling due to the preflush, the placement of polymer gel diverters in crossflowing horizontal wells, and the impact of such diverters on the subsequent inhibitor placement.

Typical recommendations stemming from these studies are discussed. For example, partitioning of fluid flow during injection and production is shown to be one of the most important factors in determining the effectiveness of squeeze treatments in horizontal wells with strong crossflow. Thus there is a need to obtain accurate production logging data to determine the effectiveness of diverter treatments in such wells.
Horizontal Gravel Packing Successfully Moved to Deepwater Floating Rig Environment
Authors: Mathis Stephen P. , Costa Luiz A. G. , de Sa Andrea N. , Tsuha Heitor , Calderon Agostinho , Arango Juan Carlos , MacDonald Ken , Hebert Scott A.
Published: December 2007

This paper demonstrates the successful application of horizontal gravel packing in the deepwater, subsea, floating-rig environment of Petrobras' Marlim field, offshore Brazil. The three gravel packs described in this paper were the first of their kind to be placed in water depths exceeding 2,500 ft (760 m) from a floating rig. The use of 13 chrome material screens require all acid treatments performed upon initial completion and during the life of the well to be well planned.

Based on the experience gained from the Marlim wells, this paper will present guidelines for drilling the reservoir section, preparing the open hole and placing the gravel. Since one of these wells is an injector, we will also present guidelines for preparing a horizontal gravel pack for water injection.

Among specific operational parameters and results we will discuss are precise gravel placement with close control over the pumping process. In addition, the gravel volumes placed demonstrate complete annular packing even in the presence of borehole washouts. As extensive in-house and industry-wide testing confirms, the use of extended-longevity well screens provided mechanical robustness and plugging resistance. We will also address the drill-in fluid and its role in preventing formation damage while depositing a filter cake that remains in place during gravel packing and then cleans up with production.

Finally, we will review performance results (such as returns and initial productivity index for each well) indicating the viability of horizontal gravel packing in all deepwater environments.
Yates Field Steam Pilot Applies Latest Seismic and Logging Monitoring Techniques
Authors: Snell J. S. , Close A. D.
Published: December 2007

A steam pilot in the Yates Field is underway to assess the economic viability of improving gravity drainage in the gas cap of the fractured San Andres reservoir. A thorough monitoring program has been implemented which employs the latest in seismic and logging technology. As steam is injected, downhole geophones monitor passive seismic events caused by thermal expansion of the rock to estimate the areal and vertical extent of the heated zone. At the same time, time-lapse carbon-oxygen logs are being used to monitor changes in oil saturation behind the thermal front. Careful design and planning are required to dedicate several wells in the pilot area solely to the application of these technologies. Results from the geophones and repeat logs will be combined to estimate the volume of oil mobilized as a result of steam injection. This volume will be compared to oil production increases and with results from fluid sampling and temperature monitoring in the pilot area to assess the economic viability of the steam pilot.
The NMR T2 Response of Crude Oils at Elevated Temperatures
Authors: Jacob James , Davis Lorne A.
Published: December 2007

Until recently, most nuclear magnetic resonance (NMR) measurements in support of lab petrophysics and well logging were conducted at room temperature. However, the T2 relaxation of bulk crude oils strongly depends on temperature. Measurement of the crude oil relaxation response at reservoir temperatures is needed for optimal interpretation of log data.

This work used a Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence to measure the NMR T2 relaxation at 2 MHz. Four stock tank crude oils were studied over the temperature range 30-100°C at a constant pressure of 300 psig. For comparison, the T2 temperature response of five viscosity standards was measured over the same range and compared to the crude oil data. A two-component exponential decay described all the data. As expected from the temperature dependence of translational diffusion, there is not a universal curve that fits all hydrocarbon mixtures. The standards and the crudes did not fit a single curve.

The observed oil T2 varied directly with absolute temperature and inversely with the viscosity. For the crude oils, the log mean T2 was related to a viscosity value calculated from the stock tank oil viscosity correlation as developed by Beggs and Robinson and modified by Egbogah (EBR). This T2 relation did not agree with a T2 correlation (SRVTM, 1994) developed at room temperature from oil samples of differing viscosity (0.7 to1000 cp). When the viscosity of one of the crude oils was measured as a function of temperature, that data then fit the SRVTM room temperature T2 correlation. Viscosity values derived from correlations based only on API gravity are evidently insufficient to make close estimates of crude oil T2 relaxation at elevated temperatures.

One of the crudes was a distinct outlier from the others. The composition of this sample suggests further investigations into the T2 relaxation of oil-based mud filtrate and mixtures of crude and oil-based mud filtrate.
Crude and Hydrocarbon Measurement Technologies
Authors: Basrawi Y. F.
Published: December 2007

The paper talks about the principles and applications of current and emerging crude and hydrocarbon flow measurement technologies. It highlights the applications of flow metering technologies, in the world and in the Kingdom of Saudi Arabia. Emphasis is put on better precision and higher accuracy in volumetric and mass custody and royalty transfer through put measurement, of crude and hydrocarbon fluids. Through finer precision and higher accuracy, when applied to exports and domestic consumption, proper accountability can be achieved and tremendous cost savings realized. " We cannot be held accountable for what we can not measure". Topics of presentation consist of the science of measurement, application of current and emerging technologies in the world of hydrocarbon measurements and the proactive role Saudi Aramco is playing in this research and application. The technologies that will be briefly discussed are, the use of the master meter in certifying crude and product meter provers as an applied technology and its comparison in accuracy to conventional methods of meter prover certification. Other devices consist of the principles and sciences of gas flow measurement, the various water-in-crude detection instruments, currently under research in Saudi Aramco and the application and viability to custody measurement, where accuracy is far more stringent than that of process condition, of the new mass and hellicoidal flow meters.
Automatic Control of Unstable Gas Lifted Wells
Authors: Jansen Bård , Dalsmo Morten , Nøkleberg Lars , Havre Kjetil , Kristiansen Veslemøy , Lemetayer Pierre
Published: December 2007

Oil production wells on gas lift are sometimes unstable at low gas lift rates, even though steady-state flow analysis gives most efficient production at these gas lift rates. Unstable production, often called heading, may lead to periods of reduced or even no liquid production followed by large peaks of liquid and gas. This results in average oil production less than expected, and oil and gas production less than the systems design capacity to allow for the production peaks without causing shutdowns.

To solve the problem the amount of lift gas is normally increased beyond the most optimum rate. When the lift gas supply is limited, other gas lifted wells must then be shut in.

This paper describes one field proven sequence based automation for oil production, plus a new model-based automatic controller. Both technologies solve the problem of unstable production from gas lifted wells through manipulation of the production and/or the gas-injection chokes. The sequence-based automation and the model-based controller stabilize the production at operating points that would be unstable under standard operation. Field measurements such as wellhead pressure, annulus pressure etc. are inputs to the controllers (or are used by the controller).

Examples are given of the model-based controller working together with realistic transient flow models of gas lift wells. Testing of the model-based controller on real unstable wells is planned.
Experimental Investigation of Proppant Flowback Phenomena Using a Large Scale Fracturing Simulator
Authors: Goel Naval , Shah Subhash N.
Published: December 2007

This paper evaluates the maximum flow rate before the sand production initiates while flowing back a reservoir after the hydraulic fracturing treatment. The experiments are performed in a high pressure slot which simulates a fracture. The slot is a parallel plate device, which is 7 ft high and 9 1/3 ft long with provisions for varying fracture gap width. The slot is filled with proppant to simulate a propped fracture, then, the closure pressure is applied with 12 actuators to simulate confining pressure on the proppant pack. Water is pumped into the slot to simulate flowing back of the fracturing fluid. The water flow rate is varied till the proppant pack destabilizes, and the sand production begins. The sand distribution is observed in the fracture with a vision system.

The experimental results show that the critical water flowback rate decreases as the closure pressure increases, or when the fracture gap width increases. However, the sand-free maximum water flow rate increases as the sand size increases for a given fracture gap width. Lastly, the cumulative sand production decreases as the closure stress decreases at a particular flow rate. The visual observations of the proppant flowback phenomena show that the sand production initiates close to the perforation. After the initiation of the sand flow, continued pumping of the water results in sand production through a channel formed in the proppant pack.
Attrition Resistant Cracking Catalysts A New Refining Standard
Authors: Higginson G.W. , Upson L.L. , Witoshkin A. , Schwint I.A.
Published: December 2007

Over the past several years, refiners have paid increasing attention to the subject of particulate emissions from stacks. One of the important refining processes that has felt the impact of this is field catalytic cracking. In many cases this has already resulted in the installation of costly electrostatic precipitators where none previously existed. precipitators where none previously existed. At the same time, the catalyst industry has responded with a number of new high activity catalysts with improved attrition resistance qualities. Not all of these "harder catalysts" attain the same. This is probably due to differences in manufacturing approach to the individual products.

Hondry's HFZ catalysts have shown the ability to reduce stack losses from FCC units. These catalysts are manufactured by the Minerals and Chemicals Division of Engelhard Minerals and Chemicals Corporation and are marketed exclusively in the Western Hemisphere by the Houdry Division of Air Products and Chemicals, Inc., elsewhere by Engelhard.

This article describes some of the recent commercial experiences with HFZ catalysts which strongly support the initial commercial evidence of the attrition resistance characteristics of these catalysts.
Win-Win Development Strategy for a Unitized Field: Fairley Baram
Authors: Yusoff Shahbehri , Salleh Alias , Kamari Yusoff Mohd.
Published: December 2007

Fairley Baram Unitized Field straddles the border of Brunei and Sarawak, Malaysia and is among the identified marginal fields that contain far greater HIIP than previous estimation. Realizing the upside potential, both joint operators, Petronas Carigali Sdn. Bhd. (PCSB) and Brunei Shell Petroleum (BSP) formed a team to review and plan for the field further development and appraisal activities.

The development phase of the campaign proved greater oil columns in proven reservoirs and developed 5.2 MMstb of oil reserves. The appraisal phase proved that the incised valley is predominantly shale filled with sand body at the base. The shale interval provides a seal and separation for reservoirs abutting to it. Deeper sands underlying the developed reservoirs were also proven to be hydrocarbon bearing. A revised volumetric incorporating the new data from the campaign indicates that the HIIP is substantially bigger than the pre-review volumes.

The re-processed 2D seismic, petrophysical, production and well data were fully utilized in the study. The deliverables are re-interpreted structural maps, in addition to the newly formulated depositional concept and revised petrophysical input. The depositional model is interpreted as an incised valley with slumping due to the tectonic movement or fall in sea level.

This paper discussed how the integrated field review enabled the team to better understand the field performance and better managed the uncertainties. The integrated field review also demonstrated that it is possible to turn around a ‘brown’ field and improved the field production rate by identifying additional proved develop reserves and at the same time replenish reserves from the appraisal targets.
Effect of Bridging Adsorption on the Placement of Gels for Water Control
Authors: Zitha Pacelli L. J. , Darwish Mohamed M. I.
Published: December 2007

Polymers and gels have been used in the past to reduce water production (water shutoff). However, only a limited number of treatments have been reported as being successful. The control of the placement of the chemicals is key factor ensure the success of water shutoff treatments. Due to the risk inherent in the use of plugging agents (polymers and gels) it became current practice to use zone isolation or dual fluid injection to ensure the placement of the chemicals in the high permeability water bearing water streaks. However mechanical zone isolation is costly and, more significantly, cannot be practiced in most wells.

Polymer and gel treatments without zone isolation (i.e., bullheaded treatments) may be expected to have a wider range of applicability provided the penetration of the chemicals in the low permeability oil bearing streaks is very small. The bridging adsorption of flexible polymers has been identified as a mechanism that can help achieving such low penetration and divert the chemicals from low (oil bearing) to high (water bearing) permeability streaks.

The aim of this work is twofold. First we improve the theory for the bridging adsorption previously presented to take into account the effect of the adsorption energy. Secondly we develop a model for the placement of polymers in linear and radial layered reservoir systems, taking into account the layer and bridging adsorption mechanisms and the Non-Newtonian character of the polymeric fluids. Steady state flow conditions are assumed for mathematical simplicity.

We found that the rheology of the polymer and the layer adsorption as such have a limited influence on the penetration depths of the polymers in the different layers as has been discussed in the literature. When bridging adsorption is taken into account, however, the penetration in the low permeability layers decreases sharply confirming our previous observations. Hence a good bullheaded placement may be achieved if the bridging adsorption is well controlled.
Summary of ASP Pilots in Daqing Oil Field
Authors: Demin Wang , Jiecheng Cheng , Junzheng Wu , Zhenyu Yang , Yuming Yao , Hongfu Li
Published: December 2007

Studying zones, geological sediments, oil and water, etc. of different characteristics, suitable ASP systems mainly with alkylbenzene sulfonate, bio-surfactant, NaOH, Na2CO3 and polymer were screened. After getting good results in laboratory studies, five ASP pilot tests have been conducted with different well spacings, zones and at different locations etc. Our aim was to study: 1) the injectivity and productivity of ASP systems; 2) the damage to the reservoir with different kinds of alkaline; 3) the method of lift and how to increase very low productivity; 4) Chromatographic separation with different well spacing; 5) the effect of this EOR method and its potential; 6) its technical and economical benefits.

Both laboratory and pilots studies showed that different zones, oil and water, and different surfactant components all require different ASP systems; bio-surfactant is compatible with alkylbenzene sulfonate; and no matter what kind of alkaline where selected in the pilot, theoretically, there is some damage to the zone, but the damage to the reservoir was not significant in the pilots, the same for chromatographic separation. Numerical simulation and pilot results both showed that more than 20% OOIP oil recovery were obtained over that of water flooding. The actual production data was better than numerical simulation. Even in a reservoir with long-term 100% water cut, the chemical cost per ton of incremental oil is around 30$ to 40$. Especially in a very low oil price situation in the world today, this method can obtain good benefits both technically and economically.

Over all, the success of these ASP flooding pilots in Daqing Oil Field are good examples on enhanced oil recovery with similar types of reservoir sediment as Daqing, and also provides a new method to achieve sustained development of resource developing companies.
Improved Production and Sand (Cold) Production in Conventional and Heavy Oil Reservoirs-A Field Case and Simulation
Authors: Wang Yariong , Chen Carl C.
Published: December 2007

A coupled reservoir-geomechanics model is developed to simulate the enhanced production phenomena in both heavy oil reservoirs (Northwestern Canada) and conventional oil reservoirs (North Sea). The model is developed and implemented numerically by fully coupling an extended geomechanics model to a two-phase reservoir flow model. Both the enhanced production and the ranges of the enhanced zone are evaluated, the effect of solid production on oil recovery are analyzed. Field data for solid production and enhanced oil production, collected from about 40 wells in the Frog Lake (Lloydminister, Canada), are used to validate the model for the cumulative sand and oil production. Our studies indicate that the enhanced production is mainly contributed (1) by the reservoir porosity and permeability improvement after a large amount of sand is produced, and (2) by higher mobility of the fluid due to the movement of the sand particles. A relative permeability reduction after a certain period of production may result in a pressure gradient increase, which can promote further sand flow. This process can further improve the absolute permeability and the overall slurry production. Our results suggest that a sand production can reach up to 40% of total fluid production at the early production period and decline to a minimum level after the peak, which can generate a high-mobility zone with a negative skirt near the formation. Such an improvement reduces the near well pressure gradient so that the sanding condition is weakened, and permits a easier path for the viscous oil to flow into the well. Our studies also suggest that the residual formation cement and capillary pressure are the key factors to affect the cumulative sand production, a crucial factor to determine the success of a cold production operation and improved well completion.