bluuebunny/crossref_metadata_2025 huggingface dataset:
Capstone Engineering Design Experience: Opportunities to Develop and Implement Skills that Work for Real People Doing Real Jobs
Authors: Ertekin T. , Harris R. , Dudenas P. J.
Published: February 2011

The capstone design courses in Petroleum and Natural Gas Engineering program at Penn StateUniversity are structured to provide students with a three- semester capstone experience. This sequence of three courses was started as a new course learning model within the context of ABET 2000 Criteria and was reformatted again during the 2007-08 Academic Year. The design sequence starts with the beginning of the spring semester of the junior year and continues during the subsequent fall and spring semesters of the senior year. These three courses provide students with the opportunity to put all the course material they have taken (and they are taking concurrently) into practice. Students typically work in three to four person teams on the same project during the last three semesters of their college education and team compositions are retained throughout the duration of the design project. The results of each phase of the design project are presented in front of a panel whose members are comprised of faculty members and industry representatives at the conclusion of each of the three semesters. During the capstone design experience students utilize and implement their analytical and numerical skills and their decision making competencies in petroleum engineering applications. Further emphasis is also placed on improving their soft skills such as written and verbal communication proficiency development during the creative process of engineering design.
Scale Deposition Prediction for Pump Design in Oil Wells
Authors: Elichev V.A. , Voloshin A.I. , Latypov O.A. , Topolnikov A.S. , Gotvig K.L. , Khabibullin R.A.
Published: February 2011

The paper presents the description of an integrated approach, which is implemented in a program module and allows predicting scale deposition in well based on distributions of specific multiphase flow parameters (temperature, pressure, and gas content). Parameters are obtained from calculated pump operation regimes. The method's apparent advantages are presented, namely: -automatic input of reservoir water/gas chemical content data,-numerical estimation of scale deposition risk in different well sections by means of the saturation index,-built-in tips on selecting the optimal scale prevention technology specifying the inhibitor type and amount,-prediction of pump life cycle buildup,-estimation of the expected economic benefit caused by scale prevention.

The prediction method of scale deposition and the algorithm of selection of the scale prevention technology can be successfully used during analysis of scale deposition risk and planning the activities for scale prevention for a group of oil wells or oilfield. The proposed algorithmic module has been tested in a number of active oil fields of Western Siberia, and has already garnered positive references from production professionals. This module is planned to serve as a basis for similar modules for forecasting risks of mechanical dashes, corrosion and paraffin buildup.
Advanced Fluid Characterization of Pauto Complex, Colombia
Authors: Martinsen Sissel Øksnevad , Castiblanco lowany , Osorio Raul , Whitson Curtis Hays
Published: February 2011

This paper presents a detailed fluid characterization study for a group of compartmentalized gas condensate & volatile oil reservoirs making up the Pauto Complex. Fluid oil-gas ratios range from 30 to 350 bbl/MMscf, producing from depths of 12,000–16,000 ft, with estimated IGIP>1 Tcf and significant oil/condensate resources.

A single equation of state (EOS) was developed to describe the complex phase and volumetric behaviour of eight reservoir fluids undergoing depletion. The EOS also describes accurately the vaporization of retrograde condensate from one of the richer reservoir fluids when contacted by a leaner hydrocarbon gas.

Years of experience in this thrust-belt basin have consistently demonstrated that the quality of fluids samples, PVT test design, lab-data QC, EOS tuning, and fluid initialization are essential to understand the hydrocarbon systems, reservoir compartmentalization, and recovery mechanisms. We show how integration of fluid characterization assists in the evaluation of depletion versus gas-injection strategies, development decisions, and ongoing reservoir management.

The methodology used in this study has general application to PVT data acquisition and developing fluid characterizations exhibiting complex phase behaviour. We also provide standardized methods to QC the thermodynamic consistency of an EOS model, particularly when binary interaction parameters (BIPs) are used extensively.

A single EOS model was developed successfully for describing the phase and volumetric behaviour of a wide range of fluids undergoing depletion and vaporization. This was achieved by modifying heavy-component properties, but more importantly, modifying BIPs extensively; these BIP modifications were possible only because considerable equilibrium compositional data was available.

We believe this paper is significant as a proven case history. With the PVT data provided in our paper, the same problem can be used to test other fluid characterization methodologies and serve as a complex phase behaviour benchmark.
Intrinsic Shale Permeability Determined by Pressure-Pulse Measurements Using a Multiple-Mechanism Apparent-Gas-Permeability Non-Darcy Model
Authors: Civan Faruk , Rai Chandra S. , Sondergeld Carl H.
Published: February 2011

We evaluate an improved method based on a non-Darcy flow model for the determination of intrinsic permeability from laboratory pressure-pulse measurements. Our approach distinguishes between the apparent and intrinsic permeability based on a model-assisted analysis of experimental flow data; the gas motion is described by considering the prevalence of different regimes, such as viscous, slip, transition, and free molecular flow conditions based on the Knudsen number criterion, under different rock, fluid, and flow conditions. This approach is applied to the experimental data obtained from pressure-pulse decay tests. The improved model is more rigorous than the previous models, provides more detailed insights, and can be used reliably for analysis and interpretation of a variety of experimental pressure-pulse tests, especially those peformed on shales.
Successful High-Temperature, Water-Control Case Histories in Highly Naturally Fractured Carbonate Reservoirs
Authors: Mercado Modesto , Acuna Juan , Hernandez Ramon , Vasquez Julio , Soriano Eduardo , Caballero Carlos
Published: February 2011

This paper presents successful field implementations of a high-temperature polymer (HTP) for water and gas-shutoff applications in highly naturally fractured carbonate reservoirs with BHT > 250°F. Fifteen case histories in a naturally fractured carbonate reservoir in Mexico (inland and offshore operations) are presented in which the HTP system was successfully applied to reduce water production. One-year, post-production data is reported for each case.

The HTP system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). To date, more than 600 jobs have been performed with the HTP system around the world to address conformance problems, such as water coning/cresting, high-permeability streaks, gravel-pack isolation, fracture shutoff, and/or casing-leak repair. Originally, the HTP system had a limited working temperature range from 100 to 250°F. The upper placement temperature of the system was ~250°F as, above this temperature, pumping times were too short. A recently developed carbonate retarder allows reasonable placement times up to 350°F, without the need for cooling down the formation to obtain enough pumping time. The retarder is not detrimental to the thermal stability of the system. The development results of this HTP system are also discussed.

The HTP system has been successfully applied to sandstone, carbonate, and shale formations requiring a conformance treatment. This system has been successfully tested to withstand a differential pressure of at least 2,500 psi and is resistant to acid, CO2, and H2S environments. To date, more than 100 jobs have been successfully performed worldwide with the HTP at temperatures higher than 250°F with the recently developed retarder. Because of the capability of the HTP system to withstand pressure, workover operations have been successfully performed in previously treated wells, including acid stimulation, sand control, and frac-pack treatments, among others.
Extending Openhole Gravel Packing Capability: Initial Field Installation of Internal Shunt Alternate Path Technology
Authors: Hecker M. T. , Barry M. D. , Sweeney C. M. , Arnold S. P. , Yeh C. S.
Published: February 2011

High angle, openhole completions are often selected to maximize production and reserve capture from several non-homogeneous sand packages in a single wellbore. Many times, the wells will require some form of sand control. Standalone screen applications may often times be the most cost effective and simplest form of sand control, but the formation characteristics may dictate that a gravel pack is necessary. Circulating water packs, alpha-beta gravel packs, have been used worldwide, but may be challenged to achieve a complete gravel pack in certain applications. Alternate Path® technology (APT), using the current eccentric two by two (2x2) shunt system, has proven to be extremely reliable in completely packing the openhole annulus and delivering high rate, failure free openhole completions.

Although routinely deployed, the current eccentric 2x2 APT screens have both technical and operational limitations. These limitations may include:

Maximum shunt system working pressure of 3,000 psi which limits the packable length to ~3,200 ft pumping at 5 barrels per minute (bpm) Risk of plugging with two independent shunt tubes extending the length of the completion Complexity of rig site connection make-up as oriented connections and cross-coupling jumper tubes are required Deployment exposure dictates that an outer shroud must be incorporated in openhole applications to protect the shunt tubes

In order to overcome some of these limitations, while preserving all of the benefits of Alternate Path technology, a new generation of gravel pack screens was developed and successfully run utilizing Internal Shunt Alternate Path Technology (ISAPT). ISAPT extends openhole packable length, increases shunt tube redundancy across the entire interval, improves rig site installation efficiency, reduces deployment exposure, and provides a platform to incorporate specially designed shunt packers to provide true openhole zonal isolation.

This paper will discuss the key differences between the new ISAPT gravel pack screens and the current eccentric 2x2 APT screens as well as validation of key objectives from the first field installation.
Hitting Bull's-Eye with Time and Cost Estimates by Combining Statistics and Engineering
Authors: Hollund K. U. , Rosenlund H. , Akcora S. , Hauge R.
Published: February 2011

This paper describes the probabilistic model used for estimating time and cost of drilling and well operations (D&W) in Statoil. The model uses statistical methodology to assist sound engineering judgment. The drilling process is broken down to a level where it is possible to identify relevant reference data and to compensate for risk. Model assumptions are made based on large datasets and applied in situations with less data.

As this method was introduced in Statoil, the estimates on a portfolio level have gone from being systematically off, to hitting bull's eye. The time and cost distributions are heavy-tailed, so there will be many projects coming in below budget and there will be dramatic overruns from time to time. But for a portfolio of unbiased well estimates, the overall delivery is much more likely to meet the predictions. With a methodology that manages to produce unbiased estimates and present the range of uncertainty the decision makers are much better equipped when making decisions on current and future projects.
Real-Time Whirl Detector Aids Drilling Optimization
Authors: Minett-Smith D. J. , Stroud D. R. , Pagett J. M.
Published: February 2011

This paper describes the design, development and use of a real-time downhole whirl detection system employed in a latest generation point-the-bit rotary steerable system (Figure 1 shows the general arrangement of the steering system). The system employs a novel yet simple whirl detection sensor design which is sensitive to whirl yet passively filters out lateral vibration. Test results presented include full-scale BHA testing in a whirl simulation rig in conjunction with field trials at a drilling test facility.

In laboratory tests, fully developed backward whirl was produced such that whirl measurements from the onboard detector could be correlated with external laboratory sensors. The combined results of laboratory testing and field trials clearly demonstrate that this new whirl measurement system is much more effective at detecting backward whirl than traditional vibration sensors. In addition, the system was capable of both detecting whirl and measuring relative intensity.

The system has been successfully deployed in field applications to provide real-time warnings, enabling corrective changes in drilling parameters to mitigate down-hole conditions and thus maximize drilling efficiency. Case studies of real field applications in the North Sea, Middle East and Central Europe are included in which the detection system was successfully deployed to optimize the drilling process, through the prevention of undesirable BHA dynamics.
A Gravel Pack System That Allows Continuous Chemical Treatment to the Pay Zone Without Interrupting Production
Authors: Surveyor Nilufer , Amaral Anderson , Kaiser Garry , Faria Nervy , Gault Kerry , da Silva Mário Germino , Moura Heleno , Nuno João , Woodford Keith
Published: February 2011

The use of semisubmersible rigs, subsea trees and workovers in deepwater wells result in costly rig mobilization. Solving problems remotely, with an interventionless method, provides huge savings and fewer risks to the operator.

This paper focuses on the preparation of the first global installation of a gravel pack system that allows continuous chemical treatment pumping to the pay zone area without interrupting production. For wells with production issues such as barium and calcium sulfates causing obstruction of the sand-control screen base-pipe holes, this system will allow pumping of scale inhibitors (or any other chemical treatment) to the end of the horizontal well (toe) or to other parts of open-hole or cased-hole sections without needing to stop production.

This system was designed to allow continuous pumping of chemicals to inhibit scaling, corrosion and other production-related issues through one small-diameter flowline down to the interior of the sand control screens at two or more distinct parts of the well (while the well is still producing) or per a specific treating program. The number of injection nodes with the same flowline conduit can vary from well to well because the system incorporates zonal isolation with feed through capabilities, using reactive element packer and multiple sequential injection nipples technology. The first installation will require only two nodes.

The system allows for screen assembly and gravel pack installation in one trip, while the flowline conduit reconnects the upper string assembly, using an anchor reconnect seal assembly. For the horizontal open hole installation, the system also incorporates a high-flow liner system for flowline conduit/sensors protection and a special feed through quick connector to simplify certain steps in the assembly, and it allows for torque transmission in open hole deployment.

This paper will describe the system functionality, identify its main components and present the test program developed to demonstrate the system consistently, qualifying it for field installation.
Innovative Technologies Enable Fast, Accurate, and Detailed Completion Evaluation and Well Performance Analysis
Authors: Huang Hao , Burch Damian , Brown William , Yin Jichao , Long Ted
Published: February 2011

In this paper, we present a workflow that allows for accurate well and completion performance simulations to be conducted automatically. A number of innovative technologies are introduced to enable this workflow. First, a mesh generator was developed to automatically construct high quality, near-well meshes for wells with different deviation angles and variable producing segments. Second, the enriched finite element method, a new numerical technique, was used to provide detailed modeling of geological features (such as horizons, natural fractures, and no-flow boundaries) and completion characteristics (such as fractured completions and perforations) without having to manually construct a mesh that honors these complex geometries in detail. Third, a procedure was developed to fully couple the completion hydraulics and the near-well porous media flows.

To demonstrate the effectiveness of the new technologies, three application examples will be detailed: (1) a sensitivity analysis of partial completion or stimulation on well performance; (2) an evaluation of the productivity of a new sand control device that uses MazeFlo™ screen technology and contains a multitude of segmented production zones; and (3) the design of a multiply-fractured completion. Throughout these examples, guidelines on maximizing the efficiency of completed segment, stimulated well length, or fractured completion are summarized.
Development and Application of a Scale Inhibitor for Electrical Submersible Pumps Suitable for Very Cold Weather
Authors: Linares-Samaniego Sandra , Spicka Kevin
Published: February 2011

Many oil producers in the Rocky Mountains region, USA, make use of electrical submersible pumps (ESP) to assist the lift of produced fluids. This region of the country is well known for its very harsh winters, with outside temperatures as low as −40 °F (−40 °C).

ESP failures resulting in increased lifting costs due to workovers, lost oil, and logistics can be caused by many factors, including reservoir solids eroding the ESP or being trapped within the intake and pump stages, mechanical and electrical problems, and scale deposition. ESPs are particularly sensitive to calcium carbonate scale formation due to the extreme skin temperatures that can develop and often require continuous chemical injection to control this problem.

Calcium carbonate scale formation in ESPs is a well known contributor to ESP failures. Large pressure drops combined with high temperatures increase the risk of calcium carbonate deposition even in mildly scaling systems. Scale formation on the motor housing acts as insulation, preventing heat transfer from the motor to the well fluids, causing the motor to be insufficiently cooled. Any scale deposition on the pump impellers can cause an imbalance and vibration, degrading pump performance.

Continuous scale inhibitor treatment of ESPs to mitigate calcium carbonate scaling is a common practice. However, the choice of scale inhibitor requires careful consideration due to the high skin temperatures that can develop and can lead to inhibitor decomposition. Effective continuous treatment of ESPs during the winter months in regions where very low temperatures can be expected require product formulations capable of withstanding these harsh conditions without significant changes to their physical properties.

This paper presents and discusses, with the aid of laboratory and field data, the development and deployment of a thermally stable scale inhibitor suitable for treatment of ESPs that can also be deployed in very cold climates, along with the monitoring tools used to ensure effective treatment.
Using DTS Flow Measurements Below Electrical Submersible Pumps to Optimize Production From Depleted Reservoirs by Changing Injection Support Around the Well
Authors: Brown G. A. , Tiwari P.
Published: February 2011

In depleted reservoirs producing with high water cuts, it is often difficult to evaluate which intervals are producing oil. Such wells typically use electric submersible pumps (ESPs) to lift the fluids, so logging operations are limited. Even when logging is possible, identifying oil production that amounts to 5% or less from a zone producing water can be a challenge.

This problem can be addressed by installing fiber-optic distributed temperature sensors (DTS) below the ESP of a well producing oil with a high water cut from multiple reservoir intervals. Differentiating between water and oil production with a DTS system is not directly possible at such high water cuts; however, by switching the water injection support from surrounding injectors on and off, the reservoir intervals being supported by each injector can be identified and the injection pattern that maximizes oil production can be found. The information obtained will allow an operator to shut off the water-only producing intervals during a subsequent workover, resulting in increased oil production from the well.

This novel application of DTS monitoring below ESP pumps in depleted, high-water-cut wells and the low-cost monitoring procedure employed has the potential to significantly increase oil production in old oil fields under water flood.
Mature Field Revitalization: The Agbara Field Case History, Offshore Nigeria
Authors: Wane B. , Angelucci L. , Tealdi L. , Ogujawa J. , Fasaanu E. , Adekanye I. , Afolabi B. , Stanisci L.
Published: February 2011

The Agbara field is operated by Agip Energy and Natural Resources (AENR) under a service contract with the Nigerian National Petroleum Corporation (NNPC). The field lies approximately 30–40 Km from the coast in the Niger Delta offshore in water depth ranging between 55–70 m. It is located in the offshore depo-belt of the Niger delta basin where thick pliocene-clastic sequences of Agbada formation have been deposited in a deltaic–fluvio-marine to inner shelf environment.

Agbara field has been on production since June 1989 and its block, OPL 472, was converted into the Oil Mining Lease 116 (OML116) on September 1999. As at December 2009, the cumulative production is approaching 100 MMBBL with an average production of about 10,000 BOPD. With over twenty years of production, the Agbara case history presented in this paper constitutes a unique example of rejuvenation of a mature oil field. This paper will provide a description of single well optimization process that led to sensible production gain in a short time frame with about 40% increase in net oil production over a six months period as well as exploration and reservoir engineering practices that provided the basis for further exploration and development opportunities in the field. An extensive review of the field and reservoir description will be provided along with the development history. This paper, the first case history of Agbara focuses on both the well engineering and the reservoir engineering aspects. Suggested or implemented workflows and technology ranging from well and reservoir characterization, candidate selection, classical water shut off, stimulation to innovative new technology such as the use of Ejector (ENI R&D) and relative permeability modifiers are described. An overview of the future potentiality of such mature field is also described.
Real-Time Measurements of Spontaneous Potential for Inflow Monitoring in Intelligent Wells
Authors: Jackson M. D. , Gulamali M. Y. , Leinov E. , Saunders J. H. , Vinogradov J.
Published: February 2011

Spontaneous potential (SP) is routinely measured using wireline tools during reservoir characterization. However, SP signals are also generated during hydrocarbon production, because of gradients in the water phase pressure (relative to hydrostatic), chemical composition and temperature. We suggest that measurements of SP during production, using electrodes permanently installed downhole, could be used to detect water encroaching on a well while it is several tens to hundreds of meters away. We simulate numerically the SP generated during production from a single vertical well, with pressure support provided by water injection. We vary the production rate, and the temperature and salinity of the injected water, to vary the contribution of the different components of the SP signal. We also vary the values of the so-called ‘coupling coefficients’ which relate gradients in fluid potential, salinity and temperature, to gradients in electrical potential. The values of these coupling coefficients at reservoir conditions are poorly constrained. We demonstrate that the SP signal peaks at the location of the moving waterfront, where there are steep gradients in water saturation and salinity. The signal decays with distance from the front, typically over several tens to hundreds of meters; hence the encroaching water can be detected before it arrives at the well. The SP signal at the well is dominated by the electrokinetic and electrochemical components arising from gradients in fluid potential and salinity. Larger signals will be obtained in low permeability reservoirs produced at high rate, saturated with formation brine of low salinity, or with brine of a very different salinity from that injected.
Optimization of Production With ICV by Using Temperature Data Feedback in Horizontal Wells
Authors: Li Zhuoyi , Zhu Ding
Published: February 2011

Horizontal wells with intelligent completion have been widely used in the field today. With inflow control valves (ICVs) production can be optimized either on individual well or at large reservoir scale. A critical step in this procedure is to understand the inflow profiles along horizontal wellbores. To develop control and optimization strategies, permanent monitoring systems such as pressure gauges and temperature sensors have been deployed with downhole control valves to provide temperature or pressure data at real time, and to translate downhole flow conditions from these data.

The relationships between temperature and inflow distribution have been developed before in intelligent well models, and these models are very useful in locating water or gas entries, and obtaining better production performances. In this work we present a new idea of using temperature feedback to directly regulate flow control valves to achieve an approximate uniform flow distribution. Instead of detecting water or gas flow in a well with different thermal properties of fluids, we aim at regulating flow distributions by monitored temperature behavior to achieve optimal flow conditions. Early-time temperature and pressure data are used to estimate permeability and initial flow profiles along the well, then developed models are applied to generate a desired temperature profile that yields an evenly-distributed flow rate along the wellbore. ICVs are operated based on the interpretation from the initial temperature data, and temperature are monitored as it approaches the desired temperature profile. By this procedure, we will be able to produce a well at an optimal condition by choking down the flow rate at higher-permeability locations along the well and therefore to increase oil flow rate and delay early water breakthrough.

This paper explains the details of the procedure. Two examples are used to illustrate the application of the method; one is for a water-drive reservoir, the other is for a water-injection case. The results show significant improvement in well performance in both examples.
Combining Resistivity and Capture Sigma Logs for Formation Evaluation in Unknown Water Salinity: A Case Study in a Mature Carbonate Field
Authors: Cao Minh C. , Saldungaray P. , Belowi A. R. , Ong L. W. , Al-Mudhhi M. A.
Published: February 2011

Formation evaluation in unknown water salinity can be done by solving simultaneously for Sw and Rw from the logs of resistivity and sigma. This has not been used extensively in the past because the logs are often acquired on wireline at various times, leading to unknown invasion effects that complicate the integration of the deep-reading resistivity and the shallow-reading sigma logs. We will show that when the two measurements are free from invasion effect - and other interpretation parameters, such as porosity, Archie m and n, etc., are reasonably known - the technique works well and gives reliable Sw and Rw answers.

Both numerical and graphical solutions are presented. The numerical technique uses a minimization routine to solve for a salinity value that is consistent with Sw calculated from resistivity and from sigma. The salient point of the paper is the graphical technique that provides better insights into petrophysics than a set of equations. It uses an overlay of equi-saturation and equi-salinity lines superimposed on the crossplot of sigma versus resistivity data. The overlay dynamically changes as porosity, lithology, hydrocarbon type, temperature, and other parameters vary with depth. The graphical technique has several applications. For the interpretation, it is used to estimate Sw and salinity, and to identify zones of changing properties. For quality control, it is used to validate the input data. For processing, it is used to select parameters and analyze their sensitivities to the results. For job planning, it is used to validate (or invalidate) the application from input values of resistivity and sigma. The graphical technique provides a valuable aid to the petrophysicist and gives an independent verification of the numerical solution.

The proposed technique is illustrated with wireline induction and sigma logs acquired in several wells in a mature Middle East carbonate field. The wells under study are completed in open hole and are flowed during logging to ensure that both resistivity and sigma logs are free from invasion effect. The results of the resistivity-sigma technique compare very favorably with those of carbon-oxygen (C/O) logging. Moreover, production logging data confirmed the results and showed that the resistivity-sigma technique provides more robust answers than C/O in low-porosity formations (below 15 p.u.).
Protecting Reservoir with Surfactant Micellar Drill-in Fluids in Carbonate-Contained Formations
Authors: Huang Tianping ‘Tim’ , Crews James B. , Clark David E.
Published: February 2011

Conventional water-based drill-in fluids contain high molecular weight polymers and different size-distribution solid particles to reduce fluid loss and carry drilling debris back to surface during the drilling process. The polymers and solid particles in the drill-in fluids usually generate near wellbore formation damage.

This paper introduces a new polymer-free and solids-free surfactant micellar-based drill-in fluid system to drill a carbonate-contained reservoir. This new fluid system contains relatively low reactivity acids mixed with surfactants and internal breakers. The drill-in fluid is designed to have low viscosities in the drillpipe. After the fluid flows out of the drill bit, the acids will react with carbonates in the formation thereby increasing the pH of the drill-in fluids. The higher fluid pH combined with the presence of dissolved divalent ions will cause the surfactants to form elongated micelle structures that will significantly increase fluid viscosity at the bottom of the hole and in the downhole annulus between the drillpipe and the formation rock. The viscosified drill-in fluid will reduce fluid loss and will carry non-dissolved drilling debris to the surface. After drilling through the targeted formation, the internal breakers in the viscosified drill-in fluid will break down the fluid viscosity to permit their removal, and the well will produce with very little or no near-wellbore damage.
A Modified Genetic Algorithm for Horizontal Well Placement Optimization in Gas Condensate Reservoirs
Authors: Morales A. , Nasrabadi H. , Zhu D.
Published: February 2011

Determining optimum well locations is a crucial step in field development. Often, broad possibilities and constrains on computational resources limit the scenarios that can be considered. When dealing with heterogeneities, the intuitive engineering judgment may not be sufficient, and use of optimization algorithms becomes necessary in finding a favorable production plan.

Although there have been extensive publications on optimization algorithms for oil reservoirs, there is little research aimed at gas or gas condensate reservoirs. In this work, we studied optimization of horizontal well placement in gas condensate reservoirs. One of the current challenges in development of gas condensate fields is condensate blockage. As pressure decreases condensate accumulates around the wellbore, leading to significant reduction in gas production. Horizontal wells can effectively solve this problem. However, due to their high cost, and complex phase behavior determining optimum locations cannot be based only on intuitive judgments.

Here we present a horizontal well-placement optimization method for gas condensate reservoirs based on a modified genetic algorithm. Unlike oil reservoirs, the cumulative production in gas reservoirs does not vary significantly (although the variation is not economically negligible) and there are possibly more local optimums. Therefore the possibility of finding better production scenarios in subsequent optimization steps is not much higher than the worse case scenarios, which delays finding the best production plan. In this work, we use a cumulative distribution function to magnify the difference between production scenarios. As a result of this change we were able to find the best scenario with considerably fewer simulations. We apply the modified algorithm to a section of Qatar's North Field, a gas condensate field with the world's largest gas reserves. Our results show that this method can efficiently find the optimum horizontal well locations and can lead to valuable increase in gas and condensate production.
Drilling Expert System for the Optimal Design and Execution of Successful Cementing Practices
Authors: Al-Yami A.S. , Schubert Jerome , Medina-Cetina Zenon , Yu Ok-Youn
Published: February 2011

Cementing is an important factor in drilling and completion operations. Good cementing practices are required for a proper advancing in drilling and production operations. Successful cementing practices start with the design of effective cement slurries. However, to the best of the authors’ knowledge, there are no standard guidelines to help drilling engineers and scientists in the effective design of optimal cement slurries to be used in different well sections.

The objective of this paper is to propose a set of guidelines for the optimal design of cement slurries, by integrating current best practices through a decision-making system based on Artificial Bayesian Intelligence. Best cementing practices collected from data, models, and experts’ opinions, are integrated into a Bayesian Network BN to simulate likely scenarios of its use, that will honor efficient designs when dictated by varying well objectives, well types, temperatures, pressures, and, drilling fluids.

The proposed decision-making model follows a causal and an uncertainty-based approach capable of simulating realistic conditions on the use of cement slurries during drilling and completion operations. For instance, well sections and drilling operations dictate the use of the proper cement design which may include the use of specific additives according to the particular modeling scenarios. These include operations on surface casing, top jobs, intermediate casings, cementing in weak formations, squeeze treatment, kickoff and isolation plugs, horizontal, and vertical completions, among others. Potential operational problems that can lead to cementing failures are also discussed. Different methods of investigation and recommendations are presented in detail.
In-Situ Combustion Dynamics Visualized With X-Ray Computed Tomography
Authors: Hasçakir B. , Castanier L. M. , Kovscek A. R.
Published: February 2011

One method to access unconventional, heavy-oil resources is to apply in-situ combustion (ISC) to oxidize in place a small fraction of the hydrocarbon thereby providing heat and pressure that enhances recovery. ISC is also attractive because it provides the opportunity to upgrade oil in-situ by increasing the API gravity and decreasing, for instance, sulfur content. Despite a considerable literature on ISC dynamics, the propagation of a combustion front through porous media has never been visualized directly. We use X-ray computed tomography (CT) to monitor ISC movement, displacement-front shape, and thickness in a 1m long combustion tube. Temperature profile history, liquid production, and effluent gas data are also obtained. Tests employ a 8.65 °API (at 21.6 °C) heavy crude oil and representative sand. The general trend of saturation profiles are defined through spatially and temporally varying CT numbers. The role of initial oil and water saturations is examined by packing the combustion tube with either multiple samples with different saturations or filling it with a uniform sample. Our work quantifies that ISC fronts display instabilities on a very fine scale (cm). ISC reactions appear to add to front instability in comparison to inert gas advance. The pressure gradients during ISC appear to influence grain arrangement for loose packing. These grain arrangements cause combustion front fingering suggesting that the geomechanical state is relevant to combustion. This new data advances the knowledge base significantly by providing a data set for benchmarking of ISC simulations.
Field Data Validation of a General Model for High-Performance Fractures in Deviated High-Rate Wells
Authors: Marongiu-Porcu M. , Naha S. , Norman D. , Ehlig-Economides C. A.
Published: February 2011

The use of deviated trajectories in deepwater completions is legitimately advocated by drilling constraints, but unfortunately production considerations have not been given the attention they deserve. A recently developed comprehensive semianalytical model using distributed volumetric sources offers a flexible and powerful computational tool that enables rigorous evaluation of a wide variety of possible flow patterns, including augmented wellbores due to "halo effects", combined flow towards the fracture and towards the remaining flowing perforations not connected to the fracture, turbulent flow effects and possible different levels of damage within the fracture and gravel pack regions.

While the generalized high-performance fracture (HPF) model clearly indicates the well performance penalty for hydraulically fracturing a deviated well, for many operators the main reason for the hydraulic fracture is sand control. The high-performance fracturing (frac-pack) completion has proven to last for a significantly longer time and through much greater cumulative production than conventional (non-fractured) cased hole gravel pack (GP) completions. A key reason for the success in deviated wells may be that even though much of the flow to the well may bypass the hydraulic fracture, as long as flow to the well is mostly uniform, the potential for failure is low.

This paper provides a broad based validation of the model using field data from a key deepwater region. Production and pressure transient data, and open and cased hole logs are used to evaluate the most likely flow geometry for each field case, and the results are compared to HPF model output. This provides a global assessment of the model versatility in modeling the production behavior of actual wells. In turn, this enables use of the model to benchmark the performance of any given well to what it could have had with more nearly optimal drilling and completion practices.
New Remediation Technology Enables Removal of Residual Polymer in Hydraulic Fractures
Authors: Crews James B. , Huang Tianping
Published: February 2011

Over the past decade, the majority of wells drilled have required hydraulic fracturing treatments to become economically profitable. The primary objective for hydraulic fracturing is to create a high-conductivity path from the wellbore to deep within the hydrocarbon-bearing reservoir. The most widely used fracturing fluid systems have been crosslinked polymer fluids. These fluids exhibit exceptional viscosity, thermal stability, proppant transportability, and fluid leakoff control. However, a major drawback of crosslinked polymer fluids is the amount of polymer residue they too often leave behind, which causes fracture conductivity loss.

This paper presents new remediation technology that will enable post-treatment removal of residual polymer from hydraulic fractures. The new technique uses nanoparticle-associated surfactants in brine that generate crosslinked-polymer-like fluid viscosity. The new fluid technology offers wall-building leakoff control that will help direct and keep the treatment fluid within the hydraulic fracture. Discussed is how new internal breakers have been developed, which remain within the surfactant micelle structures wherever they go during the treatment. After targeted remedial fluid placement and micelle breaking within the hydraulic fracture, polymer breakers held by viscosity are released to degrade the residual polymer mass within the fracture. Further presented are the components, mechanisms, and performance characteristics of the surfactant micellar fluid system and its potential for removing residual crosslinked polymer from proppant media.
Estimating Near-Wellbore Permeability in Horizontal Wells From Distributed Pressure Measurements Using an Adjoint-Based Minimization Algorithm
Authors: Zinati F. Farshbaf , Jansen J. D. , Luthi S. M.
Published: February 2011

Recent developments in the deployment of distributed pressure measurement devices in horizontal wells carry the promise to lead to a new, cheap and reliable way of monitoring production and reservoir performance. We theoretically examine the identifiability of reservoir parameters from distributed pressure measurements in the well. The wellbore and near-wellbore are described by semi-analytical steady state models, and a gradient-based inversion method is applied to estimate the permeability of layers that are perpendicular to the wellbore axis. To obtain the derivative information we employ the adjoint method which results in a computationally very efficient inversion scheme. Through several synthetic examples we investigated the effects of well and reservoir parameters, sensor spacing, and measurement noise on the quality of the inversion results. In particular we considered a 2000 m long horizontal well passing through two 300 m long high-permeability streaks in a 10 times lower permeability background. The location of high-permeability zones could be detected with a fair accuracy using 20 unknown parameters (specific PI values) even when the number of measurements was four times less than the number of parameters. Moreover, with 0.01 MPa (1.5 psi) measurement noise (and an average wellbore pressure of approximately 20 MPa (3000 psi)) the estimated specific PI profiles were satisfactory and the high permeability streaks were still detectable. However, when the noise level increased to 0.1 MPa, only the high permeable zone close to the heel was detectable. The negative effects of measurement noise and low sensor/parameter ratios are strongest in those areas of the well where the influx is smallest (usually close to the toe). The inversions typically required less than 90 seconds on a standard laptop. This offers the opportunity to extend the algorithm to multi-phase flow and dynamic applications (pressure-transient testing) while still maintaining sufficient computational speed to perform the inversion online.
Drilling Mechanics Challenges and Strategies to Reach New Exploratory Deepwater Frontiers in Brazil
Authors: Arevalo Y.I. , Medina Y. , Naslausky A.
Published: February 2011

The recent discoveries made in the presalt arena and confirmations of its huge potential have started an unprecedented exploratory campaign in ultra-deep waters by many different players. These exploratory wells are drilled in water depths exceeding 2000m with various drilling challenges depending on each specific area; however, it has been observed that to varying degrees all the wells share a common challenge of drill string failures resulting from extreme drilling dynamics events in vertical hole sections.

Conventional practices for mitigation of drillstring shock and vibrations have often proved ineffective in the mitigation of destructive vibration scenarios, and the decision to continue drilling ahead under such conditions has resulted in catastrophic outcomes. We have observed twist-offs, back-offs and BHA component failures related to shocks and vibrations.

The analysis of these recent case histories revealed that using state-of-the-art drilling monitoring tools coupled with real time optimization of parameters was not sufficient to effectively prevent the occurrence of catastrophic events. For this situation to be improved, a technique that calculates a coefficient based on the severity of drillstring vibrations to estimate the remaining life of drillstring components in real time was used as a guideline for improving decisions on when to pull out of the hole to replace and inspect drilling assemblies, thus reducing the risk of catastrophic failures. Using advanced vibration sensors to discriminate between different types of vibrations was critical estimating realistic BHA component equivalent life, which was demonstrated to be highly dependent on the type of vibration suffered by the assembly and the onset of vibration modes coupling.

The proposed approach of integrating drilling mechanics information with real-time estimation of the BHA life is proved in seven exploratory projects as a technique to assist in the prevention of catastrophic drillstring failures.
Source-Mechanism Studies on Microseismicity Induced by Hydraulic Fracturing
Authors: Warpinski N. R. , Du J.
Published: February 2011

While microseismic mapping has proven to be a valuable technology for understanding hydraulic-fracture growth and behavior, the seismic waves generated by the microseismic event also contain information that has potential value for understanding the reservoir, natural fractures, stress state, and fracturing mechanisms. Extracting information from the microseismic data requires the use of a source model, which in its most general form is represented by a symmetric moment tensor having six components. Difficulties arise when attempting to invert for the components of the moment tensor if only a single monitor well is available, but in principle the full moment tensor can be extracted for multiple monitor wells. The primary information derived consists of the slippage-plane orientation, the slip direction, and the moment (strength) of the event. Presumably, these slippages occur on existing planes of weakness, such as natural fractures, bedding planes, or potentially even fracture planes induced by the hydraulic fracture, thus providing information about the reservoir and the process. An approach for performing the moment-tensor inversion is discussed for both single and multiple monitor wells, along with methods to estimate various parameters. Both synthetic and field examples are provided to demonstrate what can be extracted from the data set under various conditions.