bluuebunny/crossref_metadata_2025 huggingface dataset:
Flow-Based Determination of Hydraulic Units
Authors: Schatz B. M. , Heinemann Z. E.
Published: December 2007

It is common knowledge that the identification of hydraulic units is vital for the construction of reservoir simulation models that preserve dynamically relevant geological features from the underlying geological model.

To date, both static-based and flow-based techniques were suggested for assessing hydraulic units. The static-based methods are used more commonly and are based on the minimization of a statistical measure of permeability heterogeneity or on establishing a relationship between log and core derived reservoir properties. The dynamic methods are based on single phase numerical simulation.

This paper presents a new flow-based method to determine hydraulic units considering multiphase flow, gravitational phase separation and capillary forces. The underlying concept assumes that, for every geological block, it is possible to estimate the time that is necessary for a fluid particle to traverse it laterally. The best way for that is a three dimensional streamline simulation. A stack of blocks can be lumped vertically to a hydraulic unit, if the time, which is necessary to achieve the vertical saturation equilibrium, is within a defined fraction of the traverse time. A multiphase simulation will be performed considering the reservoir as isolated columns. Water will be placed on top and then it will be calculated how far the vertical equilibrium can be achieved within 10 to 20 % of the local traverse time. The blocks, for which the required equilibrium is achieved, can be members of the same hydraulic unit. This method takes both the lateral flux and the vertical heterogeneity into consideration.

The paper presents a full field example to demonstrate the applicability of the suggested method.
Past Technologies Emerge Due to Lightweight Proppant Technology: Case Histories Applied on Mature Fields
Authors: Aboud Ricardo S. , Melo Ricardo C. B.
Published: December 2007

In mature fields, operators are often seeking ways to increase the hydrocarbon recovery, with the help of reputable service companies. Well stimulation continues to be, by far, the preferred method of achieving such goal. Operators and service companies are continually screening out technologies which will deliver the highest benefit/cost ratio for a particular stimulation well treatment, maintaining focus on operational and health, safety and environment excellencies.

This paper addresses the rebirth of a past hydraulic fracturing technique, born in the 50's, and how it is being successfully applied on onshore mature fields in Brazil: batch fracturing. It is effective due to several technological advancements on proppant density, becoming lighter than conventional frac sand and yet with sufficient mechanical properties to withstand bottom-hole environments. Batch fracturing is now contributing to equally efficient, and more economical well stimulation treatments, providing good economical returns to operating companies.

Batch-Fracturing had limited success in the past. This was due to the available frac fluid and proppant technologies at that time. It is desirable that proppants have low settling when carried by a fracturing fluid, from the time they are added into such fluid, until the end of the pumping process. Batch fracturing applications are on the rise, due to the new families of ultra lightweight proppants, with specific gravities ranging from 1.05 to 1.75. In batch fracturing, the proppant is added to the carrier fluid prepared in standard oilfield mixing tanks, eliminating the need of specialized mixing equipment such as blenders. Less sophisticated equipment on location implies in lower operational and logistical costs. The carrier fluid ("frac fluid") does not need to yield high levels of viscosity, and, by consequence, does not have a high load of chemicals (gelling agents, cross-linkers, related breakers…). With batch fracs it is possible to perform common but effective types of fracturing treatments, such as "skin-by-pass" (a fracture that by-passes the damaged zone), and "partial mono layer’ fracturing, both exemplified in this paper, through case histories.
Experimental Investigation of Secondary and Tertiary Gas Injection in Fractured Carbonate Rock
Authors: Karimaie H. , Darvish G. R. , Lindeberg E. , Torsæter O.
Published: December 2007

The use of CO2 has received considerable interest as a method of EOR but a major drawback is its availability and increasing cost. Therefore, as the number of CO2 injection projects increase, an alternative must be considered to meet the economic considerations. For this reason attention has been directed to nitrogen injection which may be a good substitute for CO2. The purpose of the experiments described in this paper was to investigate the efficiency of oil recovery by CO2 and N2 in fractured carbonate rock. The combined effects of gravity drainage and component exchange between gas in fracture and oil in matrix on oil recovery in fractured reservoirs subjected to CO2 or nitrogen gas injection are experimentally studied. Laboratory experiments have been carried out on a low permeable outcrop chalk, as an analogue to a North Sea reservoir rock. This was surrounded by a fracture, established with a novel experimental set-up. The experiments aimed to investigate the potential of oil recovery by secondary and tertiary CO2 and nitrogen gas injection at high pressure high temperature condition. The matrix block was saturated using recombined binary mixture live oil (C1-C7), while the fracture was filled with a sealing material to obtain a homogeneous saturation. The sealing material was then removed by increasing the temperature which in turn creates the fracture surrounding the core. Gas was injected into the fracture at pressures above the bubble point of the oil. Oil recovery as a function of time was monitored during the experiments.

Results from secondary gas injection experiments indicate that CO2 injection at elevated pressure and temperature is more efficient than N2 injection.

Results from tertiary gas injection experiments also show that injection of CO2 could significantly recover the oil, even after waterflooding, compared to N2 injection.
Risk Analysis for Comparison of Development Plans—Application of Utility Theory and Value of Information in a Real Field
Authors: Salomão M. C. , Figueiredo F. P.
Published: December 2007

At the time of selecting the development plan of a petroleum field, little information is available and the range of uncertainty is large. Once the main variables that most strongly affect the production behavior have been identified, the next step consists in generating the set of possible results for production forecast, and obtaining the probability distribution of the economical parameters, as the net present value (NPV). Depending on the range and nature of the uncertainty variables, the best way to protect the project, instead of collecting information, may consist in changing the exploitations strategy, in order to reduce reservoir risks. In next phase of exploitation of Marlim Sul field, Campos Basin, Brazil, the main source of uncertainty is an extensive fault, located in the middle of the reservoir, which breaks the oil zone into two blocks. According to the strategy of the original plan, the injection wells are located on one side of the fault, while the production wells on the other side. The sealing capability of this fault is a critical issue, since it could be an obstacle to oil sweeping by the water injection. To face this issue, we have two alternatives: either collect more information in order to reduce the level of uncertainty, or select an alternate plan, less sensible to transmissibility of that fault, and more adequate to the various scenarios. To compare these alternatives, we utilize uncertainty analyses, enriched with risk aversion considerations. The use of the expected monetary value (EMV) as parameter of comparison proved to be a good way to meet better all the scenarios, but not sufficient to traduce the economic risk of the project. The use of concepts of the utility theory indicated that the alternate plan has lower sensibility to critical uncertainty, is more protected against reservoir risks, and is the best development strategy to be implemented.
A Rigorous Stochastic Coupling of Reliability and Reservoir Performance When Defining the Value of Intelligent Wells
Authors: Aggrey G. H. , Davies D. R.
Published: December 2007

Long term equipment reliability frequently controls the Value created by Intelligent Well Technology. One of the barriers to intelligent well deployment is the inability to properly quantify Value terms of the loss of the intelligent system's ability to function properly to achieve the required reservoir or well management objectives. Recent publicised deterministic value calculation of intelligent wells does not permit proper decision making as this workflow frequently underestimates the potential value. In this paper we show a general methodology where a full stochastic reservoir reserve evaluation is coupled to a stochastic (Monte Carlo) reliability analysis of the I-well performance. This value creation is defined on the basis of a realistic mission reliability profiles for a conventional and an intelligent well.

The detailed methodology has been tested by modelling the production from a conventional and intelligent completion deployed in a typical North Sea fluvial type reservoir.

This new approach to value determination provides the information that forms the basis of a cost-effective, completion design.
Using Drillstem and Production Tests To Model Reservoir Relative Permeabilities
Authors: Matthews John D. , Carter Jonathan N. , Zimmerman Robert W.
Published: December 2007

There are many examples of dry oil production from portions of reservoirs where the local water saturation is high. When relative permeability data are available, predictions of the expected water cut are not zero, but typically 30-60%. This lack of agreement means that reservoir management using simulation models is questionable because such models can only mimic the observed reservoir production using data that bear little resemblance to measurements.

The first focus of this paper is to examine the uncertainties in the data that are used for the predictions. This then provides a numerically structured approach to adjustments that need to be made to data so that history matching of simulation models can be achieved. The relative permeabilities, rather than saturations and fluid properties, are shown to be the least certain of the relevant data.

The second focus is to explore the reasons why the relative permeability data are so uncertain. The evidence points to the fact that oil emplacement and subsequent geological history of the reservoirs have not been considered sufficiently in preparing core samples and making measurements. Greater reliance on drill-stem and early production tests is therefore crucial for deriving reservoir relative permeabilities until laboratories are able to mimic, within rock samples, oil emplacement as experienced in the reservoir.

The main source of data is from the abandoned UK North Sea reservoir (Maureen, block 16/29a).
A Probabilistic Approach for Drilling Cost Engineering and Management Case Study: Hassi-Messaoud Oil Field
Authors: Saibi Mohamed
Published: December 2007

One of the major challenges facing drilling operations engineering and management today is the prevention of costs and schedule overruns. The nature of drilling operations with the diversity of parties involved in the different tasks from well conception up to the completion, the more and more sophisticated technology used, the pressure of time, the increasing regulatory of safety and environment requirements, the inflating costs in addition to the big uncertainty of this activity make difficult meeting the financial and timing targets set for the premeditated financial resource allocation.

The first objective of this paper is to provide the drilling manager with an efficient cost management and control tool that facilitates the management of the expenditures, and enables to take informed decision and corrective actions on the right time, by providing better understanding and awareness of the actual exposure to the cost overrun risks.

Cost control techniques can be adapted to the well construction process by using the information gathered from the offset wells to mitigate the effect of the uncertainty of nature. Many studies have been made on this issue; they can be classified into deterministic and probabilistic approaches. For the latest, little work has been carried out and it is still not widely and comprehensively used in practice in spite of its powerfulness.

The methodology used in this study consists, firstly, of analyzing data from offset wells to simulate and reproduce real life scenarios of possible cost outcomes based on Monte Carlo simulation combined with risk analysis to be applied in the planning phase of new wells, and secondly, of applying a real time control and continuous improvement processes in the execution phase. This paper illustrates the case study of Hassi-Messaoud oilfield in Algeria. This type of model facilitates the management tasks and save time and efforts, particularly when dealing with intensive drilling operations in major fields.
Accurate Real-Time Resistivity Interpretation in Vertical and Deviated Wells
Authors: Frenkel Michael A.
Published: December 2007

Real-time array resistivity data interpretation is normally performed by means of point-by-point 1D inversion. Such an approach is error-prone and causes productive zones to be overlooked. In this paper, we propose a real-time 2D and 3D interpretation process for array resistivity logs. This interpretation process is able to run in real-time by relying on a set of precalculated look up tables of tool responses and a hands-off interpretation procedure. We test the method on a benchmark model and a case study. Synthetic and field examples demonstrate the capability of the technology to deliver in real-time high quality results that are now achievable only with the interpretation capabilities of a log analysis center.
An Organosoluble Polymer for Outstanding Fluid Loss Control With Minimum Formation Damage
Authors: Guichard Bertrand , Valenti Andrea , Friedheim James , Lee John
Published: December 2007

Complex well configurations with long openhole sections are often left unprotected for a long time under various conditions. Oil-based and synthetic-based drilling fluids are very well suited for drilling these long sections down to reservoir formations, providing high rates of penetration, excellent lubrication properties, and wellbore stability. The enhancement in wellbore stability and lubricity as well as reduction in differential sticking, mud losses, and formation damage can be directly influenced by fluid-loss control and filtercake properties. As an example, formation damage is largely caused by solid invasion occurring during the first step of filtration, perhaps adversely affecting the porous media permeability/stability, and consequently, reservoir productivity. Both good fluid-loss control and minimum formation damage are required for drilling and completion fluids.

A synthetic polymer, based on a unique microgel structure, has been designed to provide excellent fluid-loss control and low formation damage in OBM/SBM. Optimization of polymer morphology and fluid solubility gives a very versatile and cost-effective fluid-loss additive.

The unique microgel structure allows the polymer particles to swell and stack up, forming a thin and efficient filter cake. The ability of the microgel particles to deform under shear stress allows them to be back-produced from the formation more effectively than non-deformable additives, thus reducing risks of formation damage in the pay zone. The polymer also may contribute to the rheology of the mud by providing low shear viscosity under demanding conditions.

This paper reviews the effectiveness of the organosoluble polymer by presenting evidence of low formation damage illustrated by good return permeability data from both field and laboratory applications. Finally, data will be presented on new developments based on similar chemistry, allowing applications into more extreme conditions of temperature.
Gauge, Cutting Structure, Torque Control Components—What Really Counts for Optimal Tool Face Control With FC Drill Bits?
Authors: Barton Steve , May Henry , Johnson Simon
Published: December 2007

Toolface Control is widely regarded as one of the greatest challenges when drilling directionally with a FC (Fixed Cutter) drill bit on a Positive Displacement Motor (PDM).

Toolface offset is proportional to the torque generated by the bit. FC bits, by nature, generate high levels of torque. If an external force acting on the bit causes a FC bit to over-engage, a large change in downhole torque is typically produced, which causes rotation of the drill string, and loss of toolface orientation. It is therefore desirable for a FC bit to produce a torque response that does not vary greatly with changes in the external forces applied.

This paper examines the effect of varied components of a FC drill bit to determine the key design requirements to deliver a smooth torque response and improved directional performance. This includes evaluation of the results from a comprehensive series of laboratory tests to determine the effectiveness of a number of varied, removable Torque Controlling Components (TCC). The goal was to establish a configuration that would provide predictable torque response to applied weight on bit, allowing cutting structures to be independently optimized for overall higher penetration rates.

A novel gauge geometry was engineered to reduce drag and deliver a smoother borehole. This would provide less torque when sliding and beneficial gauge pad interaction with the borehole when in rotating mode.

Field performance studies clearly demonstrate that matching TCC, an optimized cutting structure, and gauge geometry to a steerable assembly delivers smooth torque response and improved directional control. Benefits within rotary vertical applications are also demonstrated. Successful application has resulted in significant time and cost savings.
New Approach To Ensure Long-Term Zonal Isolation for Land Gas Wells Using Monobore Cemented Completion
Authors: Taoutaou Salim , Schreuder Ron , Bosma Martin , Schoenmakers Jules , Van der Vegt Rob , Stewart Dave
Published: December 2007

Cemented completion provides an excellent opportunity for low cost drilling techniques and simple well designs to reduce well delivery costs without impact on safety or well integrity. In this concept, the completion is run straight into the open hole and cemented in place.

There is no need to run a liner and perform a traditional cleanup. The cement effectively replaces the production packer. Achieving a good cement job is essential to a successful operation. A failed cement job would require cutting and pulling of the completion before running a conventional completion and packer, unless there was a high confidence in the outcome of a remedial cement job. Therefore good conditions for cementing are a definite requirement.

Gas production and gas storage wells are particularly demanding on the cement sheaths. A failure of the sheath through de-bonding, cracking or plastic deformation results in formation fluids to enter the annulus, which pressurises the well and makes it unsafe to operate, the consequences are either losing the well altogether or, at best, an expensive intervention.

Advanced cement technology combined with state of the art software are used today to ensure a complete long-term zonal isolation of the cemented completion.

The software can model the stresses in a particular well over its entire life, including changes to the formation properties, well completion parameters, formation in-situ stresses, and operating envelope and can compare the properties of different available cements to enable the optimum cement to be selected (hole size, cement sheath thickness).

The following paper will describe the process and the engineered cement used to ensure integrity of the cemented completion and lists case histories of the 3 cemented Completions successfully cemented Onshore Netherlands.
Real-Time Simulation in Grid Environments: Communicating Data from Sensors to Scientific Simulations
Authors: Richard G. Duff , Yaakoub Y. El-Khamra
Published: December 2007

Across many fields of science and engineering computers now play a significant role in scientific discovery through both large scale simulation and real time data acquisition. As these scientific simulations increasingly require new levels of complexity and fidelity, and leveraging increasing computational capabilities, scientists are migrating their applications back and forth from workstations to supercomputers, high performance clusters, and new distributed grids of computers. For applications which depend on live real world data, the migration to varied and distributed resources provides additional challenges. This migration involves reassigning and testing individual sensor communications and data path integrity for the application before the application is ready for a real time operating environment.

This paper presents one general approach for communicating live real world data to simulations deployed on high-end computational resources. The architecture and design are presented for generic applications, before focusing on a particular scenario for drilling dynamics optimizations. In this scenario, simulations of drilling behavior depend on real time data from on-site (remote) sensors. Sensor data is streamed through to a simulation framework. The framework (available on a desktop computer or a supercomputer) displays relevant information, starts simulations with real time inputs then presents results and recommendations. For our application, we will use the Cactus Code (www.cactuscode.org) open-source high performance scientific computing framework as the simulation framework, and LabVIEW (www.ni.com/LabVIEW) as the data acquisition software. The advances in architecture portability allowed by the framework are summarized, and experiences of system uses are presented. Discussion will include opportunities found and learnings from using this platform in various environments highlighting drilling optimization.
A System for Continuous Reservoir-Simulation-Model Updating and Forecasting
Authors: Holmes J. C. , McVay D. A. , Senel O.
Published: December 2007

A significant body of work has demonstrated both the promise and difficulty of quantifying uncertainty in reservoir simulation forecasts. It is generally accepted that complete and reliable quantification of uncertainty should lead to better decision making and greater profitability. Many of the techniques presented in previous work attempt to quantify uncertainty without sampling the full parameter space, saving on the number of simulation runs, but inherently biasing and underestimating the uncertainty in the resulting forecasts. In addition, much of previous work has looked at uncertainty quantification in synthetic models and does not address the practical issues of quantifying uncertainty in an actual field. Both of these issues must be addressed in order to reliably quantify uncertainty in practice.

In this study a new approach to reservoir simulation is proposed whereby the traditional one-time simulation study is replaced with a continuous process potentially spanning the life of the reservoir. In this process, reservoir models are generated and run 24 hours a day, seven days a week, allowing many more runs than previously possible and yielding a more thorough exploration of possible reservoir descriptions. In turn, more runs enables better estimates of uncertainty in resulting forecasts. This is combined with real-time acquisition of production and pressure data, which is automatically integrated into simulation runs to allow the process to run continuously with little human interaction.

Two tests of this continuous simulation process were conducted. The first test was conducted on the Production with Uncertainty Quantification (PUNQ) synthetic reservoir. Comparison of our results with previous studies shows that the continuous approach gives consistent and reasonable estimates of uncertainty. The second test was conducted in real time on a live field. This test demonstrates the continuous simulation process and shows that it is feasible and practical for real world applications.
Gravel Packing Horizontal Wells in Reservoir Oil Flow Equalization Projects
Authors: de Magalh!es J. V. M. , de Oliveira T. J. L. , Fernandes P. D. , da Silva M. G. F. , Martins A. L.
Published: December 2007

Recent studies show that the flow along a horizontal well is not uniform or symmetrically distributed, as a larger volume of fluid enters the well near the heel. Flow equalization in horizontal wells is a state of the art strategy for assuring effective reservoir drainage and delaying the arrival of water breakthroughs. The idea is to provide a variable distribution of area open to flow along the horizontal section. The technique is applicable for several situations and is even more attractive in long horizontal section wells in heavy oil fields where friction losses in the well bore play an important role.

The concept of flow equalization has been successfully applied in onshore (slotted liners) and offshore (carbonate reservoirs) applications in Brazil. The next and most challenging step is to place gravel packs in wells where premium screens with non-uniform perforation distributions were made in the base pipe. The main issue is the excessive friction losses generated by the restricted cross flow near the heel of the well when the gravel is placed, which may generate pressures that overcome the usually low frac pressures in deepwater environments.

This article presents a case study for screen and gravel packing design for a typical deepwater application. Different screen base pipe perforation profiles are suggested and the gravel packing placement pressure was simulated. The strategy for optimizing flow equalization profiles with gravel packing pressures inside the operational window is defined by using an in house mechanistic model developed for OHGP operations.

The model was modified for this specific application, considering flow divergence during gravel placement and friction losses throughout the perforations. Results indicate that it is feasible to gravel packing screens in such scenarios and achieve attractive flow equalization results. It is important to highlight that this approach will make possible to promote an effective sand exclusion and to improve the reservoir drainage at the same time,.
Numerical Simulation of the Radial Viscoelastic flow of a Solids Free Drill in Fluid
Authors: Martins A. L. , Waldmann A. T. A. , Ribeiro D. C. , Massarani G.
Published: December 2007

Designing drill in fluids which can guarantee minimum invasion into the reservoir rock is a must for open hole completion wells. The industry has proposed several ideas to deal with the problem, most of them based on adding bridging agents to the fluid formulation. Such agents would block the pores near the well bore and, consequently, prevent additional fluid invasion into the rock, but often require acid treatment for their removal.

A different concept is proposed for controlling invasion in this article: designing a polymer based fluid which would generate extremely high friction losses when flowing through a porous media without generating extra losses while flowing in the well. In this case the fluid would present proper flow and solids transport properties in the well and would not invade the rock formation.

Previous studies by the authors showed that the viscoelastic behavior of fluids can be a major restriction to fluid invasion. This article deals with the optimization of viscoelastic parameters, such as the first normal stress difference and the extensional viscosity, for minimizing fluid invasion through oil reservoirs. The invasion analysis is based on a two phase (viscoelastic fluid + Newtonian oil) radial flow through porous media and supported by a commercial CFD package. Static and dynamic filtration phenomena are represented.

The arrival of this rheology controlled invasion concept brings to the polymer manufacturers a new challenge: the development of a highly viscoelastic polymer with non damaging behavior and adequate wellbore properties.
Investigation of a Single-Stage Sandstone Acidizing Fluid for High-Temperature Formations
Authors: Nasr-El-Din H. A. , Al-Anazi M. , Al-Zahrani A. , Samuel Mathew , Kelkar S. K.
Published: December 2007

Sandstone acidizing is very challenging because of the complex reactions that occur between the multiple-stage treatment fluids and the formation minerals. Such reactions are more likely to occur at elevated temperatures and can result in potentially damaging precipitation reactions. In conventional acid treatments, fluid is usually pumped in multiple stages of pre-flush, main fluid and over flush. The drawback of conventional sandstone acidizing treatments is that the success rate is generally low due to the uncertainty associated with the fluid-formation interactions.

This paper presents the results of a laboratory investigation of a single-stage sandstone acidizing fluid designed to address some of the problems associated with conventional sandstone acidizing fluids. The application of the fluid system is sandstone reservoirs with bottom hole static temperatures greater than 200°F.

Core flow tests demonstrated that the single acid system minimized the potential for precipitation due to secondary and tertiary reactions. This system did not cause sand deconsolidation, and maintained the integrity of sandstone cores. Corrosion tests conducted for low-carbon steel and 13 Cr coupons demonstrated that the fluid had lower corrosion rates.
Advances in Coiled Tubing Re-entry Access Bypassed Reserves on Alaska's North Slope
Authors: Madarapu R. , Lasley B. M. , Corson C. S. , Hinze I. , Carey S.
Published: December 2007

Technology improvements continue to advance the capabilities of coiled tubing directional drilling (CTDD). Alaska's North Slope, with its prevailing dedication to expanding the technological envelope, has served as a testing ground where advanced CTDD techniques mature into economically viable systems.

Even after over 500 successful CTDD sidetracks on the North Slope, impetus remains to further improve this economical drilling technique. Through a close working relationship between field operator and the service company, significant research and development has led to the introduction of novel tools and services to overcome the intrinsic hurdles of conventional CTDD.

Through a process of miniaturization and innovation, small-diameter systems have been developed for CTDD. The most recent introduction of tools and services includes rib steering technologies, bidirectional wireless mud pulse telemetry, gyro-based MWD services, and ultra-slim, high-resolution, real-time resistivity.

Straighter, longer horizontal laterals, improved steering, and real-time resistivity in openhole sizes as small as 2 3/4-in. ID has been achieved, consequently improving precision in geosteering within the narrowest of payzone.

This paper highlights two case histories describing CTDD technology, real-time formation evaluation, and multilateral drilling processes used to access previously unreachable oil-bearing rock on Alaska's North Slope. While proven in this region, CTDD advances are applicable in other mature fields for the economical extraction of additional reserves.
Technology and Capability requirements for Well-Centric Production Optimization
Authors: Lee Jaedong , Vachon Guy
Published: December 2007

One of the main challenges in the oil industry is to optimize production while reducing the development cost and maximizing reserves. Real-time optimization has been gaining ground to effectively face the challenge, and it has been applied in the Smart field or Digital field technology. Literature references two optimization loops, the reservoir-centric slow loop and the well-centric fast loop. Intelligent wells are focused on the fast loop and combine well-centric technologies with monitoring, data analysis, modeling, interpretation and automation to accelerate production, maximize recovery and reduce operating and capital expenditure cost. Their benefits include increased ultimate recovery, accelerated production and cost reduction. Intelligent well equipments can include intelligent completion system, artificial lift system, and automated chemical injection system.

Information regarding the optimal intelligent equipment configuration for a well at various points in its life requires the convergence of multiple talents pools. It is discovered in the well design process but it is unreasonable to expect all the relevant talent to be available during actual well operations. As a result, the well may not optimize production or add the value that was expected unless the knowledge is captured and used to assist making optimization decisions in real time. This knowledge is the linked to improved use of the data that is recorded and transmitted by downhole and surface sensors. Instead of closing the loop by human intervention, an intelligent optimization system will link stored knowledge to measurements. This will change the optimization activities from polling to interrupt-driven, and will advise when wells deviate from their expected behavior in ways that prompt diagnosis of problems early enough to avoid them.

This paper presents the technologies and capabilities come together to achieve intelligent optimization system.
Optimization of Surfactant-Based Fluids for Acid Diversion
Authors: Nasr-El-Din H. A. , Al-Nakhli A. , Al-Driweesh S. , Welton T. , Sierra L. , Van Domelen M.
Published: December 2007

This paper examines the use of surfactant gels during acid injection and describes the optimization of these fluids. Unlike available viscoelastic surfactants used today in the field, this surfactant is cationic at low pH values. If used in live acids, the fluid has relatively low viscosity when pumped. However, once the acid is spent the surfactant molecules significantly increase the fluid viscosity. To further enhance diversion, the acidic fluid can also be foamed. Alternately, brine gelled with surfactants can be foamed and utilized for diversion.

Rheological measurements were conducted on Hastelloy fitted rotational viscometers at temperatures from 70 to 300°F. The effects of surfactant concentration and acid additives on the apparent viscosity of various surfactant-based fluids were investigated in detail.

The surfactant was found to be stable and compatible with most acid additives. Some corrosion inhibitors adversely affected the apparent viscosity of surfactant solutions. The apparent viscosity increased with salt concentration. The apparent viscosity of the surfactant solutions can be predicted using Carreau-Yasuda model. Coreflood tests indicated that the surfactant delayed acid breakthrough in carbonate cores. Acceptable corrosion rates were obtained when this surfactant was added to the acid.

The performance of this surfactant was validated with field trials. The surfactant was used in more than fifty field treatments. It was used with up to 28 wt% HCl as in-situ acid diverter. It was also used to enhance the stability and apparent viscosity of foams used for acid diversion in power water injectors.
Constructing Oil Exploration and Development Project Portfolios Using Several Risk Measures—A Realistic Example
Authors: Lasdon L. , Faya L. C. , Lake L. W. , Dyer J. S. , Chen W.
Published: December 2007

This paper describes scenario generators and portfolio models for oil and gas exploration and production (E&P) planning. The problem is how to allocate funds to a set of oil recovery projects to achieve a desired tradeoff between risk and return. A mix of development and exploration projects is assumed, further stratified by reservoir depth and uncertainty level of reserves. The scenario generator incorporates distributions for seven uncertain reservoir parameters, obtained from engineering and geologic data in the Tertiary Oil Recovery Information System (TORIS) database (http://www.netl.doe.gov/scngo/Petroleum/Software/database.html). Capital and operating expenditure data comes from the IHS Energy Discovery Module (www.ihsenergy.com). A slightly compressible-liquid tank model is used to model the yearly oil production from each well in each project. Oil price trajectories are generated using a mean reverting model. A complex income and tax calculation evaluates the net present value (NPV) of free cash flow, and a Monte Carlo simulation generates NPV scenarios for each project.

We describe and compare optimization models that minimize several risk measures, including variance, semivariance, expected loss, and loss probability, as well as models that maximize expected utility. Risk measure values, optimal project weights (assuming any level of fractional participation is allowed in all projects), and portfolio NPV distributions arising from the various risk measures are compared, and contrasted with results of widely used ranking procedures that ignore risk.
Video Microscopy of Methane Gas Production from CBM Coals
Authors: LaReau Brian , Pope John , Buttry Daniel , Lamarre Robert , Noecker Bret , MacDonald Steven , Van Lieu Neil
Published: December 2007

This invention relates a method and apparatus for studying the desorption of gases from coals using optical microscopy. Such desorption reveals the ways in which production of gas from coal occurs under various completion and production scenarios. It can also reveal the efficacy of various stimulation and enhancement methods. The invention discloses methods and apparatus that enable simulation of coalbed reservoirs in a laboratory, and teaches how correlating various analytical techniques with said microscopy can allow researchers to readily evaluate coalbed reservoir properties and production factors.
Optimization of Oil Production Based on A Capacitance Model of Production and Injection Rates
Authors: Liang X. , Weber D. B. , Edgar T. F. , Lake L. W. , Sayarpour M. , Al-Yousef A.
Published: December 2007

This paper presents a methodology to optimize the value of oil produced by adjusting the water injection rates in a mature field.

The reservoir is considered to be a multi-well input-output system with the injection rates as the inputs and production rates as the outputs. A simple capacitance model based on control volume of a given producer is fitted to total injection/production data obtained from a three dimensional reservoir simulator. A power law relationship models the instantaneous water-oil ratio as a function of the cumulative water injected. An optimization problem for oil production is formulated to optimize future performance, where oil production rates and water injection rates are optimized simultaneously based on the selling price of the oil produced and the cost of water injected or the disposal cost of water produced.

The simulation results show that the simple capacitance model satisfactorily captures the long-time behavior between injectors and producers. The solution of the constrained optimization problem for oil production using nonlinear programming can maximize the future economic return of the reservoir asset. Various patterns of optimal injection are followed under different revenue objectives. The optimal injection rates depend on the cost of water injected/disposed, which leads to some wells being shut in while other wells operate at their maximum values.

The proposed optimization method can be used for realtime production control and is appropriate for simultaneous optimization of well rates in a field where injectors are shut-in frequently.
Case History and Appraisal of the West Buffalo Red River Unit High-Pressure Air Injection Project
Authors: Kumar V. K. , Gutierrez D. , Moore R. G. , Mehta S. A.
Published: December 2007

The West Buffalo Red River Unit (WBRRU) project is one of the three High-Pressure Air Injection (HPAI) projects in the Buffalo Field. It produces from the Red River reservoirs, which are deep (~8,400 ft), thin (~15 ft), hot (215 °F), low permeability (~10 md) carbonates. The unit comprising 4,560 acres with 15 producing wells was formed in July 1987 and began air injection operations four months later.

Before unitization the oil production was declining steadily but the response to air injection has resulted in a significant production increase over its historical decline. While unit production in July 1987 was 200 BOPD, a peak production rate of 500 BOPD was achieved in January 1990 with 15 producing wells, after the injection of 2 BSCF of air. As of December 2006 about 23 BSCF of air had been injected, for a cumulative oil production of 2.3 MMSTB since the beginning of injection.

This paper reviews the production and economic performance of the WBRRU high-pressure air injection project to date. The production performance analysis includes estimates of incremental oil recovery due to air injection using conventional decline curve analysis, the expected ultimate recovery using the volume-burned method, and a discussion on how air utilization has changed over time. A detailed economic evaluation is carried out using different economic yardsticks such as net present value and incremental rate of return. A discussion on the impact of oil price on the economic profitability of the project is presented as wells as an estimate of the minimum oil price required for attractive economic results.

To date, the HPAI project in WBRRU continues to be a technical and economic success. In year 2005 old vertical producers were re-entered to drill horizontal laterals and take advantage of the great reservoir response to injection.
Historic Agreement Establishes Training Program for Petroleum Reserves Evaluators
Authors: Black Michael , Olds Dan , Harrell D. Ronald
Published: December 2007

This paper describes the process through which the E&P industry has recognized and acted upon meeting the need for consistent and global training of petroleum engineers and geoscientists responsible for estimating oil and gas reserves. The SPE, AAPG, SPEE and WPC have created "The Joint Committee On Petroleum Reserves Evaluator Training" (JCORET), which is developing a library of training modules that represent industry "best practices". Many, perhaps most, petroleum reserves evaluators worldwide have never participated in training opportunities that truly represent industry-recommended practices.

The sole purpose of JCORET is to develop high quality training modules to be presented and taught to professional reserves evaluators by industry experts at an affordable cost. The program will remain "evergreen" to accommodate new technology and unconventional reservoirs.
Effect of Droplet Size, Emulsifier Concentration, and Acid Volume Fraction on the Rheological Properties and Stability of Emulsified Acids
Authors: Al-Mutairi S. H. , Hill A. D. , Nasr-El-Din H. A.
Published: December 2007

Acid-in-diesel emulsions have been extensively used in matrix acidizing and acid fracturing treatments. This acid has several advantages including lower corrosion rate, minimum number of additives, and deep acid penetration. For stimulation purposes, the most important properties of emulsified acid are reactivity, stability, and viscosity. The size distribution of the droplets of the emulsion affects these properties.

The purpose of this paper is to correlate the droplet size of the dispersed phase (acid) to the viscosity and stability of emulsified acids. Measurements of the droplet size were acquired with laser diffraction techniques and analyzed using an advanced image processing system. Viscosities were measured using Brookfield PVS rheometer at varying temperatures and pressures. The stability of the emulsified acid was monitored using an HTHP see-through cell.

Shear viscosity was measured for emulsions with droplet sizes ranging in diameter from 1 to 20 qm. The viscosity covered a shear rate range from 10 to 750 s−1 and temperature range from 25 to 80 °C. All measurements were regenerated for emulsifier concentrations of 1, 5 and 10 gpt. It is noticed that finer emulsions have higher viscosities. Likewise, similar measurements were performed with varying acid volume fractions.

The most stable emulsion was noted at an acid volume fraction of nearly 0.7. Other volume fractions were stable for a few hours before diesel was expelled as a separate layer above the emulsion. Eventually, the remaining emulsion restabilized at acid volume fraction of 0.7.

This paper discusses the effects of acid volume fraction, emulsifier concentration and droplet size distribution on the rheological properties of emulsified acid.
Productivity Impairment Due to Kaolinite Mobilization: Laboratory and Field Experience, Oseberg Sør
Authors: Fleming Niall , Mathisen Anne-Mette , Eriksen Synnøve H. , Moldrheim Erlend , Johansen Thomas Rudberg
Published: December 2007

Oseberg Sør field, operated by Hydro Oil & Energy, is situated 130km west of the Norwegian coast on the eastern flank of the Viking Graben structure. It consists of fault bounded structural units of varying geological complexity. Within these units the reservoir intervals are of moderate to poor quality and can exhibit strong contrasts in permeability and formation water composition. Reservoir pressure support is provided by combined injection of gas and Utsira aquifer/produced water. The wells are a combination of platform and subsea and include extended reach horizontals with complex geometry and lesser numbers of vertical well.

Coreflooding has been undertaken on material from the major producing intervals (Ness, Middle & Upper Tarbet and Upper Jurassic). This coreflooding has been used to assess potential formation damage resulting from application of oil based mud or scale inhibitor squeeze treatment. In all instances, the major cause of formation damage was the mobilisation of kaolinite that can form up to 20wt% of the bulk rock and occurs in all producing intervals. Coreflooding demonstrated that even at very low flow rates (30ml/h) permeability was reduced by up to 99% during initial plug saturation and before the onset of treatment. Modification of the coreholder allowed multi-port permeability measurements to be made that gave an indication of the depth of damage.

Field evidence only gives an indirect indication of the effect of kaolinite mobilization on well productivity. For example, a gradual reduction in well productivity has reversed after squeeze treatment. This gradual decline is possibly a result of the migration of kaolinite during well inflow with consequent reduction in permeability. Squeezing could have caused the dispersion of kaolinite away from the near wellbore with an increase in well productivity.

Given the adverse results obtained from coreflooding due to kaolinite mobilization, significant effort has been directed towards identify methods by which to reduce its impact, through incorporation of clay stabilizers in scale inhibitor squeeze treatments and remedial treatments using mud acid stimulation. Laboratory results of these evaluations will be presented (mud acid coreflooding results were not available at the time of writing).

While the occurrence of kaolinite on Oseberg Sør has potentially reduced well inflow performance, it has had a positive influence on scale inhibitor squeeze lifetimes. A field example will be given to show this.