bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Interpretation Method of 4D Seismic for Estimating Steam Chamber Extent
Authors: Tanaka Motonao , Endo Kenji , Nakayama Toru , Onozuka Shigenobu
Published: October 2009

This paper presents a new interpretation methodology of 4D seismic data to determine the steam-chamber distribution generated by the SAGD operation in the Athabasca oil sands. Thin mudstone layers and abrupt changes in facies present difficulties upon SAGD implementation. 3D seismic surveys were conducted in 2002 to aid in understanding of the facies distribution, and in 2006 to evaluate SAGD performance.

Two methods are demonstrated to estimate the steam-chamber areal distribution. The first approach is based on comparison of seismic traveltime maps from the two 3D surveys, and the second method uses the interval P-wave velocity (Vp) from the top to the bottom of the reservoir transformed from the seismic traveltime. We formulated a petrophysical model that expresses Vp as a function of temperature, pressure, and water saturation based on the previous experimental measurements of seismic velocity with oil-sands cores. Scaling factors for Vp reduction were first estimated to adjust the laboratory scale to field scale and distributions of Vp reduction and traveltime changes corresponding to the steam-chamber conditions were calculated.

Vp and traveltime maps that reflect the high pressure and high temperature zones generated by the SAGD process were obtained and distributions of Vp reduction and traveltime were calculated with the petrophysical model in order to decouple composite effects of temperature and pressure. Effects of pressure were assumed to be areally more extensive than temperature effects. By distinguishing high temperature and high pore-pressure zones from low temperature and high pore-pressure zones, the steam-chamber distribution was determined. The steam-chamber distribution obtained by the traveltime approach did not show a very good agreement with the well production performance, while the Vp approach presented consistent results. The bitumen volume in the steam-chamber zone estimated by the new approach was calculated, and compared with the actual bitumen production.

The methodology demonstrated here can be applied to other 4D seismic data at fields under thermal recovery processes.
Flow Assurance Design and Initial Operating Experience from Blind Faith in Deepwater Gulf of Mexico
Authors: Subramanian S. , Price M. P. , Pinnick R. A.
Published: October 2009

This paper discusses the flow assurance design and operating strategies for the high pressure high temperature Blind Faith development located in deepwater Gulf of Mexico. Key fluid property issues identified during the early design stages and appropriate flow assurance strategies adopted to mitigate risks in developing the field will be presented. Design aspects of the subsea insulation systems deployed to support flow assurance will be discussed in detail. An OLGA® model based Flow Management Tool (FMT) was developed prior to field start-up to provide asset team engineers and operators with live information on calculated well production rates, steady state thermal performance of the flowlines with forward looking projections on cooldown times for hydrate management.

Results from initial benchmarking efforts aimed at comparing the flow assurance design against actual subsea system operating performance will be presented. Field observed cooldown data for subsea equipment (trees and manifold) and data relevant to flowline thermal performance will be presented as part of the discussion on benchmarking efforts. Results will be presented from field tests done after start-up to test impact of flow assurance strategies such as LDHI (Low Dosage Hydrate Inhibitor) injection for hydrate mitigation on the topsides water handling system. Lessons learned and best practices from the start-up and early operating phase of the project will be shared.
Experimental and Theoretical Studies of Three-Phase Relative Permeability
Authors: Ahmadloo F. , Asghari K. , Jamaloei B. Yadali
Published: October 2009

The three-phase relative permeability relations define the hydrodynamics of fluid flow in porous medium. These relations are necessary for simulation of various phenomena occurring in the reservoir during various production and enhanced oil recovery (EOR) processes; such as chemical flooding, steam flooding, enhanced gas drives, etc.

Despite the availability of a modest number of relative permeability measurements reported in literature since 1941, there is no universally accepted conclusion reached on the shape of the isoperms. Given this scarcity of consistent experimental data, it is difficult to recommend any of the developed predictive models, e.g. empirical, mechanistic, or pore-level, for the estimation of isoperms of each phase under reservoir conditions. This paper presents a review of a wide rage of experimental results reported on three-phase relative permeability and highlights their salient features and distinctive findings. It also provides indepth evaluation of technical achievements in this field. The present study is a useful reference for engineers and scientists interested in modeling of multi-phase flow in porous media, and provides guidelines on the selection of predictive models for generation of three-phase relative permeability isoperms.
Application of Risk Based Inspection to Offshore Facilities
Authors: Poulassichidis Tony
Published: October 2009

The Risk Based Inspection (RBI) process delivers a calculated risk value for each fixed equipment item in a facility. Fixed equipment risk values are the product of the Likelihood-of-Failure (LOF) and the Consequence-of-Failure (COF) factors. The calculated equipment risk values are used to optimize the facility inspection program in accordance with industry best practices (API-580/2002, API-581/2008).

This paper will present the results from a RBI analysis of Gulf of Mexico (GOM) topsides facilities. Requirements for successfully implementing and maintaining a RBI program will be reviewed.

Using the RBI calculated risk values, a fixed equipment relative risk ranking is established that strengthens the facility mechanical integrity program by allowing the operator to:

– set priorities and focus their attention on the critical areas – justify capital investment for lifetime extension projects – proactively address loss of primary containment and process safety issues

In addition to improved mechanical integrity, using RBI as a basis for inspection planning can aid in a cost/benefit optimization analysis of inspection work year over year.

Recent regulation updates require compliance with the API-510 inspection code for production operations in the "outer continental shelf" (30 CFR 250.803.b). API-510 code translates to a time-based inspection interval requirement after a maximum of 10 or 15 years in-service depending on pressure vessel classification. As an alternative to the time-based inspection requirements, the API-510 inspection code allows the use of RBI analysis.

In the case of this particular GOM platform, the RBI analysis resulted in an 80% reduction of the above-mentioned time-based inspection requirements while at the same time ensuring equipment mechanical integrity needs are met.

In conclusion, RBI technology is an intelligent database system compliant with industry best practices for fixed equipment risk management

decision enabler for asset management based on a quantitative data analysis allowing the operator to do the "right thing", focusing on cost effectively reducing operational risk
Experimental Study on High Viscosity Oil/Water Flow in Horizontal and Vertical Pipes
Authors: Vuong D. H. , Zhang H. -Q. , Sarica C. , Li M.
Published: October 2009

The average crude oil produced around the world becomes heavier every year. High viscosity oil multiphase pipe flows are experienced during the production and transportation of heavy oils at normal temperatures or conventional oil at low temperatures. Heavy oil is normally produced with low GOR but considerable water cut due to cognate or enhance oil recovery reasons. Since high viscosity oil-water two-phase flows were not well understood, an experimental study of high viscosity oil-water flows in horizontal and vertical pipes with a 50.8-mm ID has been conducted to investigate the effect of high oil viscosity on flow pattern, pressure gradient and water holdup.

The observations and measurements of flow pattern, pressure gradient and water holdup were obtained over the ranges of oil and water superficial velocities from 0.1 to 1m/s for horizontal and verical upward flows. The pressure was maintained at 2 MPa using compressed Tulsa City natural gas. Non-additive Lubsoil ND 50 was used as test oil and filtered tap water as water phase. Oil viscosities varied from 0.22 to 1.07 Pa·s. The flow patterns and oil-water mixing status were observed through a sapphire window and the images were recorded using high speed and high definition video cameras. The flow patterns were mostly dispersion of oil in water and water layer (DO/W&W) for horizontal flows and core annular flow for vertical flows. Extensive measurements of water holdups and pressure gradients at different superficial velocities, viscosities and inclinations were acquired and analyzed.
A Simplified Subsea Separation and Pumping System
Authors: Håheim Svein , Gaillard Xavier
Published: October 2009

Subsea gas/liquid separation and pumping is an effective means of providing artificial lift for enhanced oil production from subsea oilfield developments. Compared to multiphase pumping the energy efficiency may be improved by a factor of two to four, depending on the water depth. A subsea separation and pumping system is, however, more challenging to operate, as the liquid level in the separator needs to be controlled to ensure a stable liquid feed to the pump. The pump must also either be protected from gas surges or designed to be gas tolerant. For deepwater applications this becomes even more challenging, as compact separation solutions are required, due to the difficulty of manufacturing subsea separators to withstand the high hydrostatic pressure.

This paper describes conceptual design and model testing of a subsea separation and pumping system, using a gas tolerant, Hybrid Helicoaxial-Radial pump. The slug-handling characteristics of the system are discussed, and a control strategy capable of handling any realistic slug size and frequency is described. A key feature is that active subsea control valves are not required, reducing the complexity of the subsea facilities and control system.

The system design and control strategy was verified by model testing. A pressurized air water loop was used, with maximum liquid flow rate of 166 m3/h (25.000 bbl/d) with a gas volume fraction (GVF) at separator inlet of up to 70%. Pump suction pressures up to 30 Bar were used. The testing proved that overall control system response time of 1-2 s is required to handle typical slug frequencies, which is well within the capabilities of present subsea control systems and Variable Speed Drives.
Plunger Lift Dynamic Characteristics in Single Well and Network System for Tight Gas Well Deliquification
Authors: Tang Yula
Published: October 2009

This paper presents a study for plunger lift characteristics to dewater tight-gas wells operated in the Piceance basin of Rocky Mountains with multiple-well pads and surface pipeline network. The wells’ TVDs are about 6000 ft with deviated paths, and the water-gas-ratio (WGR) is 40~80 stb/MMscf. The objective is to understand the optimal operating conditions for reasonably controlling deliquification without severe liquid surge while maintaining maximum gas production.

The IPR and reservoir depletion are based on tight gas model, which considers the transient IPR due to very low matrix permeability, hydraulic-fractures and drainage radius. A transient dynamic multiphase flow analysis has been performed to investigate the plunger lift effectiveness, performance and optimization for different scenarios. Simulation runs were performed for early, middle and late field life which corresponds to different reservoir pressure and productivity index. It shows that liquid loading becomes severe and production becomes unstable (heading) with decreased reservoir pressure and increased water influx. Eventually the well production can stop due to liquid loading. Plunger lift helps to maintain the production and reduce the instability. A network model with 22 wells on a pad has been built to study the interaction of the system and the liquid surge control strategy.

Plunger-lift process for tight gas wells with liquid loading problems needs integrated dynamic modeling for both reservoir and wellbore systems. The philosophy of optimization is that, the reservoir and wellbore system should be the "master" for production optimization, and surface control should serve as a "slave" system.
Control-Relevant Selective Grid Coarsening
Authors: Vakili-Ghahani S. A. , Jansen J. D.
Published: October 2009

From a system-theoretical point of view there are only a limited number of degrees of freedom in the input-output dynamics of a reservoir system. This means that, for a given configuration of wells, a large number of combinations of the state variables (pressure and saturation values) are not actually controllable and observable from the wells, and accordingly, they are not affecting the input-output behavior of the system. In an earlier publication we therefore proposed a control-relevant upscaling (CRU) methodology that uniformly coarsens the reservoir model based on the relevant level of information and control. Here we present a selective (i.e. non-uniform) grid coarsening method to allow treatment of very large models with high degree of heterogeneity in their parameter fields. In this control-relevant selective coarsening (CRSC) method, the criterion for selective grid size adaptation is based on the controllability and observability properties of the reservoir system; hence we selectively coarsen only the weakly controllable and observable parts of the model. The CRSC method is particularly attractive for use in flooding optimization or history matching studies for a given configuration of wells. We applied our algorithm to two numerical examples and found that the CRSC algorithm can accurately reproduce results from the corresponding fine-scale simulations, while speeding up the simulation.
All-in-One Concept with Expandable Tubular and Swellable Elastomer Technology—A Systems Approach to Well Design
Authors: Young Ifeh , Ekeigwe Austin , Alabi Tunde , Oluwatosin Adedeji , Obanya Phillip
Published: October 2009

GU field high rate gas campaign was selected by management as a pace setter project to deliver NAG to the Nigerian LNG trains project as part of the overall strategy of implementing the revitalized performance improvement initiative in Nigeria. To deliver top quartile performance at lower unit technical cost without compromising on safety and sustainable community development, an innovative well design philosophy with game changer technology was proposed.

The approach utilized a number of innovative techniques; slim well design with 2-casing string philosophy; 1-skin strategy and casing flow design. The 9 5/8" string acted both as the surface and production casing with the shoe above shallowest hydrocarbon. The build up, landing and drain section was drilled in a single trip through several unstable and reactive shale sections hence the "all-in-one approach". The 7" production liner was combined with 5 ½" expandable sand screen lower completion in a single trip. The 5 ½ Expandable Sand Screen was compliantly expanded to the 8 ½" drain hole.

Unlike previous concepts where zonal isolation was provided with cement, zonal isolation was provided with swellable elastomers bonded and spaced out on the 7" production liner. GU-11ST well was successfully completed as a single string single gas producer with 7" 13 Cr completion tubing.

The well tested to a facility-limited rate of 52 MMscf/d with FTHP of 3423 psig and condensate rate of 3900 bbl/d psi. Extrapolated well test results showed that the well can produce at 120 MMscf/d at a draw down of ca. 18psi; with extra swing capacity to go up to 160 MMscf/d when required. Several well testing challenges were addressed during the cleanup and flow period.

The systems approach on well design in GU-11ST resulted in lower unit technical cost compared to other wells in the campaign. It has also proven to be a future enabler to implementation of the small location concept with light and less expensive rigs without compromising safety and well objectives.
Modeling of Complex Fluid Systems in Gimboa Field Block 4: An Offshore Field in Angola With Biodegraded Heavy Oils
Authors: Yang T. , Mengel F. , Lannotta A. , Lazary J. , Mouzinho E.
Published: October 2009

The Gimboa Field, which came on stream from April 2009, has produced different reservoir fluids compared with the fluid initialization model developed before production. The early exploration well only discovered highly biodegraded heavy oils (low API) in the field. Although some normal black oils (high API) were initialized in some reservoir segments based on the fluid samples taken during drilling of injection wells, the existence of large amount of non-biodegraded black oil had been underestimated before starting of production.

The EOS fluid characterization was developed with good accuracy for limited initial reservoir fluid samples. All the initial reservoir fluid samples were taken from the same geological region. This made it difficult to have a reliable estimation of fluid distributions in other reservoir regions. Different ways to initialize the reservoir fluids have significant impacts for estimation of reservoir fluid in place, the expected drawdown pressure between the water injection wells and the producing wells, water injection speed and volume, the required gas handling capacity and finally the recovery factor.

Drilling of water injectors and producers provided an opportunity to collect more reservoir fluid samples from other parts of the reservoir. Integration of available PVT, pressure gradients, and geochemistry data from the Gimboa Field provided an updated estimation of the reservoir fluids in different reservoirs. An API tracking black oil model has been selected to describe lateral fluid variation. Uncertainty is discussed as a lesson learned from this field for the later design of sampling programs for similar fields.

This paper provides an insight into the importance of fluid initialization for compositional varied reservoirs. Integration of multidiscipline data is an efficient way to reduce uncertainty in fluid initialization.
Analysis of Production Decline in Waterflood Reservoirs
Authors: Yang Zhengming
Published: October 2009

Despite the widespread application of reservoir simulation to forecast waterflood performance, petroleum engineers still need simple production decline analysis methods to forecast oil production and estimate ultimate oil recovery from the production history data.

For pressure depletion recovery processes, Arps proposed an empirical model and Fetkovich validated the Arps model based on the transient and semi-steady state solutions. However, for waterflood reservoirs, reservoir pressure is generally maintained and oil production decline is mainly due to the reduction of oil saturation and oil relative permeability.

This study explains the inconsistencies when the Arps production decline model is used as a framework to forecast the waterflood recovery process. An analytical oil production forecast method specifically for waterflood based on the Buckley-Leverett theory has been developed. This study compares forecasts by the new method with field performance data and reservoir simulation results. These comparisons demonstrate the straightforward, convenient and accurate application of the new forecast method for waterflood reservoirs.
Determining Reservoir Properties and Flood Performance from Tracer Test Analysis
Authors: Shook G. Michael , Pope Gary A. , Asakawa Kazuhiro
Published: October 2009

In the last several years a variety of new tools for interpreting interwell tracer tests have been developed. The new methods are based on residence time distributions of the tracer, where much of the previous work used only the mean residence time. Using the distribution of residence times extends the power of moment analysis by allowing for the determination of reservoir properties and flood performance as a function of time. Flow geometry and construction of flow capacity - storage capacity diagrams also follows directly from the analysis. Swept volume vs. time, and sweep efficiency are also determined from the residence time distribution, as is remaining oil saturation. One important key to these new methods is our use of the integrated tracer recovery histories. Estimating residual oil saturation is greatly simplified by our mathematical treatment of slug tracer injection. Examples are presented that show improved saturation estimates even at early times in a tracer test.

This paper describes the new analysis methods developed recently and shows by comparisons with analytical and experimental data that the methods are accurate and robust. The method is simple and can be done with a spreadsheet using only produced tracer concentration data; it does not require a reservoir model or numerical simulation. The equations are derived from first principles for a very general case that includes both conservative and partitioning tracers produced from any heterogeneous reservoir.
Isolation Valve Contingencies Using Wireline Stroker and Tractor Technologies
Authors: Schwanitz B.
Published: October 2009

With today's high rig operating costs, identifying areas where new technology can be used to improve efficiency and reduce rig-time is critical to many a project's financial success. In deep water regions, new intervention solutions that are not rig dependent are especially desirable. Electric wireline deployed interventions have been shown to offer both technical and financial benefits in mechanical manipulation of downhole hardware, such as isolation valves, in that they are faster to mobilize and execute, saving the operator several days in rig-time and deferred production compared to pipe conveyed methods.

Many deep water completions use down hole isolation valves for temporarily closing off production while awaiting flowline connections for first oil. These isolation valves can be shifted open or closed through surface commands while a backup (contingency) allows the valves to be mechanically shifted. Failure of these valves can result in expensive delays to production with large rig time costs to intervene.

Operators in the Gulf of Mexico, West of Shetland and West Africa have been pioneers in the application of wireline conveyed mechanical solutions for isolation valve contingencies. The contingency consists of an electric wireline hydraulic stroking tool to shift the sleeve open or closed. The wireline stroker is either wireline tractor conveyed in high angles or run with only the shifting tool attached in low angles. A new intelligent shifting tool is also available for opening and closing valves on command to avoid hang ups on downhole profiles that may occur with the conventional spring-loaded shifting tools.
Application of Relative Location Techniques to Induced Microseismicity from Hydraulic Fracturing
Authors: Reyes-Montes J. M. , Pettitt W. S. , Hemmings B. , Haycox J. R. , Andrews J. R. , Young R. P.
Published: October 2009

Microseismic monitoring is routinely used for imaging the fracture network induced by hydrofracture treatments. One of the principal sources of uncertainties in the location of hypocentres is the velocity structure used in the location algorithm, which in most cases is approximated by layered models from sonic logs or estimated from perforation shot arrival times. Hypocentral uncertainties can be reduced by an order of magnitude, and the number of events located significantly increased, by using relative location methods that reduce the location volume to a small region around the seismic source.

Relative location methods are valid provided that the separation between the processed events is small compared to the ray-path lengths between source and receiver. The location is obtained through the inversion of differential travel times with respect to one chosen master event, minimizing the relative moveout residual. In this study, a new step-wise master-event relative-moveout location is applied to microseismic events induced during hydrofracture treatment.

The unique step-wise addition to the technique overcomes the limitations of separation distance by constructing a lattice of master events formed by all available good quality events that are located with a classic location algorithms. The minimization search is extended to the complete fracture volume as defined by the master events, converging to a solution that minimizes the relative moveout residual with respect to any of the available masters within the distance range. The use of arrival time differences with respect to a master event allows the location of events with P- and/or S-wave arrivals. Using the step-wise approach, the increased resolution in seismic location achieved by relative location methods is propagated to the complete set of events in a hydrofracture treatment. Furthermore, the method allows a significantly higher number of events to be located as only one phase (P or S wave) need be identified, assuming the events are in the vicinity of a master event with high quality arrivals.

We provide results from an example data set to illustrate the higher resolution and increase in number of located events that can be obtained through the application of the stepwise relative-moveout location algorithm.
A Robust Measure of Heterogeneity for Ranking Earth Models: The F-PHI Curve and Dynamic Lorenz Coefficient
Authors: Shook G. Michael , Mitchell Kameron M.
Published: October 2009

A new method for estimating heterogeneity in Earth models is presented. The new approach requires running a streamline simulator only a few timesteps, so multi-million cell models are evaluated in minutes. Using streamline time of flight and volumetric flow rate information from the simulation, a flow capacity diagram and sweep efficiency history can be determined. Five different measures of heterogeneity can be obtained from these two diagnostic plots.

We then evaluated each of these measures of heterogeneity for 450 models that were constructed using a wide range of Dykstra-Parsons coefficient and correlation lengths, and 2 different well patterns. The measures of heterogeneity were plotted against discounted oil recovery to determine the best measure of heterogeneity. From this study we conclude the Lorenz coefficient – as determined from dynamic data – is the single best measure of heterogeneity.
The Influence of CO2 Solubility in Brine on CO2 Flooding Simulation
Authors: Yan Wei , Stenby Erling H.
Published: October 2009

The solubility of CO2 in brine is considerable under high pressure where CO2 flooding processes are carried out. The dissolution of CO2 into the large amount of brine/water either initially present in reservoirs or later injected into them is therefore a non-negligible factor in CO2 flooding simulation, especially simulations of CO2 injection into water flooded reservoirs and CO2 water-alternating-gas (WAG) injection. In this work, the Peng-Robinson equation of state (EoS) modified by Søreide and Whitson was further improved to describe the phase equilibrium between CO2 and brine. The EoS model was then combined with a robust multiphase flash subroutine to form the core of a one dimensional slimtube simulator. The simulator provides a flexible description of the phase equilibrium between the water phase and the hydrocarbon phases. Water can be treated as an inert phase, or only dissolving CO2, or both dissolving CO2 and vaporizing to the hydrocarbon phases. The effect of CO2 solubility and water content in hydrocarbon phases on CO2 flooding simulation can therefore be investigated. With the slimtube simulator, a series of one-dimensional continuous CO2 flooding with water initially present in the reservoir were simulated using different phase equilibrium descriptions. The difference caused by different phase equilibrium descriptions was discussed in terms of saturation and composition profiles, final recoveries, minimum miscibility pressure, delay in gas breakthrough time, and CO2 loss to the brine phase. It was also investigated how the difference changes with pressure, temperature, initial water saturation, and brine salinity.
Extraction of Dissolved Methane in Brines by CO2 Injection: Implication for CO2 Sequestration
Authors: Taggart Ian
Published: October 2009

The solubility of CO2 in underground saline formations is considered to offer significant long-term storage capability to effectively sequester large amounts of anthropogenic CO2. Unlike EOR, geosequestration relies on longer time scales and involves significantly greater volumes of CO2. Many geosequestration studies assume that the initial brine state is one containing no dissolved hydrocarbons and therefore apply simplistic two component solubility models starting from a zero dissolved gas state. Many brine formations near hydrocarbons however tend to be close to saturation by methane. The introduction of excess CO2 in such systems results in an extraction of the methane into the CO2 rich phase which in turn, has implications for monitoring of any sequestration project and offers the possibly additional methane mobilization and recovery.
Advanced Automatic Control for Dual-Gradient Drilling
Authors: Breyholtz Øyvind , Nygaard Gerhard , Nikolaou Michael
Published: October 2009

Managed pressure drilling offers unprecedented capabilities for precise pressure control in drilling operations. This capability, created by the availability of new hardware tools, creates the need for tight coordination of such tools, to ensure reliable and safe operation. The use of model predictive control is proposed as a multivariable control framework that can coordinate multiple variables to offer both better performance and higher reliability and safety compared to current practice. A case study on a dual-gradient drilling system is presented to demonstrate how model predictive control can simultaneously control bottomhole pressure and hook position during drill string movement, by simultaneously manipulating the main pump flow rate, seabed pump flow rate, and drill string velocity. Computer simulations show that the proposed approach results in much lower bottomhole pressure deviations during drill string movement that manual control of hook position alone. The implications of this study as well as future directions for integration of additional variables and use of appropriate model predictive control variants are discussed.
Acoustic Logging Techniques for Guiding Casing Recovery Operations in Deepwater Gulf of Mexico
Authors: Donovan Glenn , Fadesere Peter
Published: October 2009

While ultrasonic logging devices have been used in recent years to determine the likelihood that casing strings are unbonded and thus free to be removed in a casing recovery, this application is still under development. The uniqueness of this application lies in the fact that the bonding forces present on the outside of the casing are caused by drilling fluids in varying stages of decomposition as opposed to cement. The fact that the exact composition of these altered fluids is unknown makes it difficult to quantify their compressive strength, leaving no clear method for anticipating an acoustic response. Virtually all of the acoustic devices in use today, when used for any application other than borehole imaging, were developed to quantify the ability of cement in the casing-formation annulus to provide a pressure barrier between zones connected to one another by the wellbore. In every such case, the cement used to provide the isolation is of a known chemical composition and extensive laboratory experiments are conducted to precisely measure its compressive strength and other properties. Since there exists no such opportunity to measure the properties of the material in an uncemented annular space, theoretical solutions have been developed which estimate the extent of adhesion these materials cause. This paper discusses the applicability of such theoretical solutions and substantiates its conclusions with case studies.
Application of Beam Pumping Wells’ Energy-Saving Rebuilding Techniques in Daqing Oilfield
Authors: Wang Fengshan , He Liu , Wanfu Zhou , Guochen Shi , Gang Cao , Ruiqing Chang , Deshi Zhang , Dingming Lin
Published: October 2009

Daqing Oilfield is the largest continental oilfield of China. And beam pumping system was the main artificial lift method of the oilfield. Till the end of 2008, the number of producers has reached more than 48,000 in the whole oilfield, in which 80% wells applied beam pumping system. Statistics indicated that, the averaged efficiency of beam pumping systems was only about 25% for the whole oilfield resulted in large quantity of power waste. Moreover, the power consumption of beam pumping wells was about one third of the total power consumption of the oilfield development which was the largest part of operation cost.

In the past tens years, Daqing Oilfield invested huge funding to improve beam pumping equipments’ energy-saving techniques. And a series of energy saving rebuilding techniques were developed including two innovative beam pump units, three energy-saving motors, and two new control designs. This paper presented these energy saving techniques in details. Application in more than 2,000 producers indicated that the efficiency of beam pumping systems was improved considerably after using these innovative energy-saving rebuilding techniques.
Development and Real Field Application of Two Novel Upscaling Methodologies for Simulating flow in Heterogeneous Reservoirs
Authors: Rai Himansu , Chaudhri Masroor
Published: October 2009

Scale-up techniques are commonly used to coarsen highly detailed geological models with the objective of maintaining near well flow behavior and reservoir connectivity. Existing single phase permeability upscaling methods (ranging from purely Local, Extended Local, Quasi-Global and Global) suffer with limitations in maintaining both near well physics and reservoir connectivity. In this paper we address this challenge by proposing two novel methodologies for single phase permeability and transmissibility upscaling, wherein we combine the individual strengths of purely local and extended local methods in a very practical and efficient manner for capturing the reservoir connectivity and near well region behavior.

The first method is based on calculating the effective coarse scale transmissibility from an extended local method and calculating coarse scale permeability from a local method. The local method derived permeability is used to calculate the well PI and effective transmissibility calculated from extended local method is used as a derived property to override the transmissibility generated from purely local method. The second method is based on calculating the effective coarse scale transmissibility from an extended local method while preserving near well region properties using a LGR (local grid refinement) extracted from the fine scale model. The process of defining LGR around wells is fully automated.

These methodologies are applied to upscale real field simulation models used for well optimization for deepwater reservoirs. The new methods showed considerable improvement over other existing upscaling methods. Also, these methods are highly applicable for any well count and well placement optimization study as there is no need to perform any additional upscaling every time well location changes.

The proposed new upscaling methods provide a practical way of combining different strengths of existing local and extended local methods. They can be easily used in real field well placement and optimization studies as demonstrated, removing a practical limitation of other combination methods of requiring new upscaling to be performed every time well location changes during any well optimization study.
Dynamic Flow Simulation of a Well Clean-up Operation at the Åsgard Field
Authors: Krogh Espen , Mjaaland Svein , Sletfjerding Elling
Published: October 2009

Clean-up operations of oil and gas wells are carried out when newly drilled wells are started up and tested for the first time. An optimal clean-up can be important for the production properties of complex wells. As the clean-up process is highly dynamic in its nature, a conventional steady state approach for simulation is of limited value.

In the current work a clean-up case study of a dual branch long horizontal well at the Åsgard field was undertaken using a commercial transient multiphase flow simulator. Eleven production zones located along the main and lateral horizontal wellbores were modelled in detail with separate zone productivities (obtained from petrophysical data analysis) and different numbers of sand screens with inflow control device (ICD) in each zone. Simulations of different clean-up scenarios were performed prior to the real operation and the results were used to plan the clean-up. The simulations supported the decision to clean-up both the lateral and the mainbore simultaneously in one operation.

The operational data from the clean-up operation were compared to the model results and valuable data for tuning of the model were obtained. After tuning a good match between the simulation results and the operational data was obtained, also quantitatively.

The study confirmed that dynamic simulations can be a useful tool to predict and understand the behaviour of a clean-up operation.
Fracture Mapping in the San Juan Basin, New Mexico
Authors: Estrada Erick , Roberts Neale , Weijers Leen , Riebel Tom , Logan Steven
Published: October 2009

An infill drilling pilot test in the Lewis, Mesaverde and Dakota formations of the San Juan Basin, New Mexico, included microseismic and tiltmeter monitoring of fracture stimulations. This study looks at microseisms from eight stages in two wells using an 18-tool stacked toolstring and surface tiltmeter measurements of 23 stages in six wells, (including the microseismic wells), using a 63-site tiltmeter array. A pressure observation well also situated within the pilot area, provided key information to the interpretation of data from the Lewis fracture stages. Complex (dendritic) fracture growth observed in the Lewis formation may be controllable through modification of the injection rate. Lower injection rates encourage simple planar growth and control fracture-height growth. Shorter fracture half-lengths were observed in the lower Mesaverde stages, leading to a redesign that is currently being tested in the field. The average fracture azimuth measured in this project, N21°E, confirmed the current understanding of the stress orientation in this part of the San Juan Basin and provided confidence regarding additional infill well placement.
The Quest for Energy in the Black Sea
Authors: Antonini Massimo , Kasparian Krikor
Published: October 2009

The quest for hydrocarbons in the Emerging Countries has always been one of the main reasons for the expansion of the Energy Companies.

Areas where opportunities are still to be completely understood, unlocked and exploited are the Countries facing the Black Sea shores, mainly Bulgaria, Romania, Turkey and Ukraine. In the past few years the drilling activity has rejuvenated due to the increase in the energy demand for both the local populations and the growing industry: Energy Authorities have set their goals wanting to become more independent on hydrocarbons supplies from the Russia. In recent years a few small energy companies have started to look into this area of opportunities also with drilling activity supported mainly by economically viable discoveries in the gas field lying under the Black Sea. After years of absence, the Major Companies have also started to look into this area as to become one of their working arenas.

Background political and economical situations dictate the recent moves into the Black Sea: Ukraine is always struggling against the Russian giant to have its energy needs fulfilled, Romania and Bulgaria have joined the Euro-zone in 2008 with the urge of developing their economies having at present dimensions a few folds lower than the most industrialized European Countries; finally Turkey has been for the last two decades a wannabe of the European Community. All four have strong reasons to be energy independent, also for detaching from a long established mark of underdeveloped Countries
Stimulation Results and Completion Implications from the Consortium Multi-well Project in the North Dakota Bakken Shale
Authors: Olsen T. N. , Gomez E. , McCrady D. , Forrest G. , Perakis A. , Kaufman P.
Published: October 2009

Stimulation Results and Completion Implications from the Consortium Multi-well Project in the North Dakota Bakken Shale

After a great deal of success with Bakken open hole horizontal completions in Richland County, Montana between 2002 and 2005, operators began to move to the more aerially extensive, yet heterogeneous North Dakota side of the Bakken play in the Williston Basin. However, the early results in the North Dakota Bakken were much more variable than the Richland County Bakken wells. With the huge resource at stake in North Dakota, it was realized that better understanding of the nature of the formation's transmissibility, completion, and stimulation efficiency could shorten the learning curve on the economic exploitation of this important oil resource. For this reason a consortium was formed with seven operators, a major service company, the state of North Dakota, and the DOE to drill and complete three science wells. Extensive vertical and horizontal log and core data were collected in these wells. Two wells were completed and one well was utilized as a monitoring well. During the stimulation several seismic arrays were deployed to map out the micro seismic events, including the largest seismic array ever deployed in a horizontal well. In addition, multiple radioactive isotope (RA) and fluid chemical tagging were employed.

This paper presents some of the results of this project and the completion analysis that was done with this data as well as other released data in the Williston Basin. In addition, some conclusions are drawn on the nature of fracture initiation along the wellbore and an attempt is made to provide some insight to the completion optimization.
Characterization of Hydraulically-Induced Shale Fracture Network Using an Analytical/Semi-Analytical Model
Authors: Xu Wenyue , Thiercelin Marc , Walton Ian
Published: October 2009

A model describing hydraulic fracture network growth is presented in this paper. The model is fully constrained by accounting for mechanical interactions between injected fluid and fracture walls and among nearby fractures and by satisfying observation data including wellbore pressure and microseismic event distribution. It may be solved analytically or semi-analytically, depending on whether a quasi-steady approximation is made.

The mathematical framework of the model is first discussed to certain detail. The model is then applied to a Barnett Shale case to illustrate the procedures of characterizing a hydraulically induced fracture network via inverse modeling and predicting the growth of the fracture network using forward modeling. Detailed information including fluid pressure, fracture width, fracture permeability, fracture volume and the surface area of fracture walls are also obtained during the course of modeling. It is further applied to carry out parameter sensitivity analysis. Its potential in realtime applications is also discussed.
Design Criteria and Application of High-Density, Brine-Based Fracturing Fluid for Deepwater Frac & Packs
Authors: Qiu Xiaoping (Victoria) , Martch Eddy , Morgenthaler Lee , Adams Jerry , Vu Hiep
Published: October 2009

Completing deepwater Gulf of Mexico (GOM) wells with depths greater than 20,000 ft and high geopressure may require the use of higher-density fracturing fluids to reduce high wellhead treating pressures. In Shell's Deimos field, frac fluid density of up to 12.5 ppg was required. Although the industry has pumped 11.5 ppg NaBr-based borate cross-linked fracturing fluids, a 12.5 ppg NaBr-based borate cross-linked fracturing fluid has not been used until now. There are many challenges when applying a 12.5 ppg NaBr-based borate cross-linked fracturing fluid.

The 12.5 ppg NaBr high-density, brine-based fluid has significantly different rheological behaviors than typical fracturing fluids made with freshwater or low salt concentrations. The high-density, borate cross-linked fluid responds very differently to shear history and recovers much more slowly than does freshwater-based fluid. Breaker efficiency is also very different. The high-density, brine-based fracturing fluid is potentially incompatible with formation crude. Base brine quality was also critical to final fluid quality and quality control procedures had to be better defined.

Shell developed lab and field QA/QC protocols to ensure the fluid met the frac & pack job requirements. With rigorous fluid testing and optimizations, three wells in the Deimos field were successfully completed in 2007.

This paper summarizes the extensive rheology, fluid compatibility, fluid optimization, and fluid QA/QC processes. It also summarizes important aspects in the application of 12.5 ppg NaBr-based fracturing fluids. This paper will also discuss friction pressure, treatment pressure, actual frac & pack job performance, and postjob production data. The fracturing fluid design and test methodology applied in these three Deimos wells are also very beneficial to design and optimization of other kinds of fracturing applications.
Hydraulic Intelligent Well Systems in Subsea Applications: Options for Dealing with Limited Control Line Penetrations
Authors: Tirado Ricardo
Published: October 2009

Throughout the past decade, the reservoir management and interventionless flow control benefits of Intelligent Well Systems have made them a perfect fit for deepwater developments. Approximately 90% of current deepwater wells are subsea, and the number of subsea wells is expected to continue to grow. To enable subsea operators to reap the rewards of intelligent well technology, the industry (operators and service companies) is working to interface downhole intelligent well equipment with subsea trees and controls. Currently, the hydraulic penetration requirements of intelligent wells and the limited number of hydraulic penetrations in many existing subsea trees prohibit some subsea operators from using intelligent well technology. Manufacturing lead times for subsea trees and control systems are usually quite long. Rather than interrupt rig and operation schedules for an extended period while waiting for new equipment with more penetrations, operators often choose not to run intelligent well systems, and sacrifice the resulting benefits.

This paper will address various technologies and methodologies that are currently available to enable operators to benefit from intelligent well technology in subsea wells with limited number of penetrations. The case histories covered will illustrate how it is possible to reduce the number of hydraulic control lines required to remotely operate downhole flow-control valves without sacrificing overall system reliability.