bluuebunny/crossref_metadata_2025 huggingface dataset:
Cement-Bond Evaluation: A Step Change in Capabilities
Authors: Kessler Calvin , Bonavides Clovis , Quintero Alberto , Hill Jim
Published: October 2011

A new, small-diameter ultrasonic scanning logging tool has been field tested and commercially deployed for simultaneous cement-sheath and casing evaluation. The tool is designed for use in 9-5/8-in„ heavy-weight casing down to 4-1/2-in. casing.

Enhancements in downhole electronics, computing capabilities, and telemetry transmission allow the new circumferential acoustic scanning tool to operate on 7/32-in., 5/16-in., and 9/32-in. mono-conductor e-line cables, which allow for the data acquisition to be performed off a small foot print cased-hole unit with a smaller, lighter tool at the same logging speed as previous generation tools run off a seven-conductor e-line cable on an open-hole unit. The enhanced portability and evaluation capability in casings as small as 4-1/2 in. make the system ideally suited for land operations.

Analysis of the cement data is accomplished with the same statistical variance process that has been widely used over the years to analyze data provided by all ultrasonic logging tools available in the industry, resulting in a robust and easy-to-interpret computed product in traditional, light-weight, and foam cement.

The cement-evaluation process uses the measured acoustic impedance of the material in the casing-formation annulus. The casing's internal diameter is obtained from the twoway travel time and the measured borehole-fluid travel time. The casing-wall thickness is determined from the frequency content of the reflected waveform data. Both internal diameter and wall thickness are used to determine internal and external casing wear. Legacy ultrasonic scanning tools could not provide quality data in small-diameter casing because of tool size and tool-fishing constraints and near-field transducer ring-down effects.

A new, interactive job-planner program has been developed to optimize data acquisition for casing size, weight, and borehole fluids. The planner determines the number of shots per scan and maximum logging speed required for the tool to provide 100% circumferential coverage without sector gaps or interpolated data.

Examples comparing the multi-conductor circumferential acoustic scanning tool and the mono-conductor circumferential acoustic scanning tool in conventional and nonconventional cement slurries are presented.
A Novel Methodology to Develop Relative Permeability Inputs for Field Simulation Models for the Solution Gas Drive Process in the Tengiz Reservoir
Authors: Padmakar A. S. , Schembre Josephina , Kamath Jairam
Published: October 2011

Predicting primary depletion recovery below the bubble point is a very difficult challenge, especially for carbonate reservoirs. Accurate predictions require sufficient laboratory data to cover the variability in response from the different rock types and laboratory procedures, and proper upscaling of laboratory data to simulation grid scales.

Many recent studies have shown that laboratory derived gas oil relative permeability curves often depend on whether the tests were conducted using depletion drive or steady state methods. Though it may seem preferable to use depletion drive derived laboratory data for modeling solution gas drive recovery, these tests are complex, quite expensive and it is not practical to conduct many depletion tests. In a previous study we recommended conducting few specialized experiments to gauze the effect of solution gas drive process on the relative permeability data sets and make the requisite corrections to the steady state plug data accordingly. In this work we build further on this methodology and we have analyzed all the available gas-oil relative permeability data to date for the Tengiz reservoir after applying the requisite corrections for the solution gas drive process. We show that the P10, P50 and P90 classification of the relative permeability data set varies considerably depending on the response variable of interest such as recovery or productivity. Finally, we demonstrate a simple and robust workflow to generate a single set of low-mid-high gas oil relative permeability curves for use in full-field simulation models which incorporates all the different measurements on the plugs, the requisite corrections for the depletion process as well as the various effects on the response variables.
Modelling of Cable Forces as a Decision Support Tool for RLWI Operations
Authors: Kjærsgaard-Rasmussen J. , Rask N. , Iversen M. , Arnskov M. M.
Published: October 2011

Subsea well intervention has been performed extensively over at least two decades to service wells and to increase recovery from these wells.

It is a well known fact that subsea wells normally underperform platform wells in recovery between 15–20%. To a large extent, the gap in recovery is related to the high cost in access to the subsea well compared with surface or platform wells. Efficient and low cost well intervention techniques are of the outmost importance for increased field recovery. Riserless Light Well Intervention (RLWI) is one of the tools helping to close the recovery gap.

RLWI operations are now common in shallow water depth up to 600 meter although at least one operation has been performed on 906 meter water depth.

Considerable efforts have been made to improve the RLWI system with respect to efficiency, weather sensitivity and at last – but not least – deep water compatibility.

During RLWI in deeper water, the environmental loading on the wireline from the vessel to the subsea equipment becomes the limiting factor as the wire is subjected to considerable loading from sea current.

Welltec, one of the pioneers in RLWI operation have started an R\&D program to fully understand the limitations and to provide the operator with a tool to assess if RLWI is possible based on simulated behavior and empirical data instead of merely stating that RLWI is not possible beyond a certain water depth.
Accelerating Petro-Technical Learning in the E&P Industry
Authors: Edmundson Henry , Pickering Stephen
Published: October 2011

Accelerating Petro-Technical learning is a key requirement for all players in the upstream industry. It is the only solution for resolving the industry's demographic crisis of skilled professionals, and it is also key for ensuring that our skill-base is equipped to exploit the hard to extract oil and gas now that the easy resources are exploited. This paper describes the the key factors in implementing an accelerated learning program.

The key to acceleration is maximizing the efficiency of learning, achieved by using a competency management approach that ensures that learning fits defined paths of personal development. It is also essential to balance different learning modes in a blended approach. These include learning from instruction-led classes, integrated workflow classes that combine technical and software components, learning from coaches and mentors, self-study, and learning on the job.

The paper review the key factors in accelerated learning and reviews the challenges in implementation.
In-Situ Viscosity from Acoustic Logging
Authors: Dyshlyuk E. , Parshin A. , Charara M. , Nikitin A. , Plyushchenkov B.
Published: October 2011

This work contributes to a concept proposal for obtaining pore fluid viscosity and formation permeability from thermoacoustic measurements (i.e., conducting acoustic logging of pore fluid mobility at different temperature conditions in the wellbore).

The acoustic method for mobility estimation from Stoneley wave attenuation and dispersion is widely used in the industry. Currently, nearly all wireline measurements are performed at static thermodynamic conditions in the wellbore. But what happens if thermodynamic conditions are changed and logs are run at different temperature conditions at a given depth? In this case, the measurements of the pore fluid mobility at different temperatures allow obtaining additional information on the pore fluid viscosity and improve the accuracy of permeability estimation by the acoustic method.

This work includes experimental and modeling verification of the suggested thermoacoustic method. The experiments were on laboratory core samples; finite-difference poro-visco-elastic code was used for the modeling. The applicability of the method is shown to be dependent on the temperature difference of the formation, accuracy of the Stoneley wave dispersion and attenuation measurements, and the in-situ wellbore pore fluid viscosity, temperature, and pore pressure.
Case History of the World's First Installation of Continuous Chemical Treatment in a Horizontal Openhole Gravel Pack to Inhibit Scaling While Maintaining Production Levels
Authors: Surveyor Nilufer , Amaral Anderson , Pinto Marcela
Published: October 2011

Offshore deepwater fields usually require a semisubmersible rig to drill and complete their wells. Additionally, if any intervention is required in the well, a costly workover rig will need to be moved to the site. Hence, solving problems remotely using a method requiring less intervention can provide substantial savings in the overall cost of the well.

Such an opportunity emerged when working on a project in the offshore oilfields of Brazil, where use of water injection as a reservoir energy maintenance method is common. However, the mixture of water injection wells and oil producing wells can lead to the formation of barium sulfate on downhole equipment, which can precipitate under pressure change during production.

Barium sulfate's insolubility makes its removal difficult; usually requiring the use of special tools for mechanically cleaning the gravel pack screens’ interior. This type of intervention method requires an offshore rig. It demands a considerable amount of time and resources to complete the cleanup procedure, especially in the case of long openhole horizontal gravel packs. However, by pumping inhibitors directly to the gravel pack screens’ interior, production suspension is avoided, along with any intervention-related time and cost.

This paper will describe the world's first installation of a horizontal openhole gravel pack system specifically designed to allow continuous pumping of scale inhibitors. The chemicals were injected through a single flowline down to the interior of the sand-control screens at two distinct parts of the well pay zone, without interrupting oil production in offshore Brazil. This pay zone management system incorporates a hydraulic wet connector, an openhole zonal isolation packer, and two chemical injection mandrels with flow regulator valves. The mandrel valves evenly distribute the barium sulfate inhibitor, preventing its deposit inside the screen.

Potential applications of this system in offshore Brazil are being considered on the basis of this successful first installation. Results of this project, as well as other compelling data, suggest that operators may benefit from its incorporation in their field development plan, maximizing their return on investment.
RFID Provides Multiple On-Demand Activation/Deactivation Reliability to Underreaming
Authors: Gonzalez Luis A. , Valverde Eddie , Laird Tommy
Published: October 2011

There is a need in the industry to advance the technology in underreaming, specifically in operations where simultaneous drilling and underreaming take place. Underreaming hurdles have existed for several years that could not be overcome by a simple reliable mechanical apparatus to activate or deactivate the tools. Activating a tool on demand offers options and underreaming techniques that can enhance the way wells are drilled.

Traditional underreamers are activated or deactivated by dropping a steel ball to the tool via the drillstring. The dropped ball creates a bore restriction in the underreamer, which only allows drilling fluid to pass. RFID (Radio Frequency Identification) activation offers several key advantages; it creates an option to increase the performance of the underreamer by allowing multiple activation or deactivation without restricting the ID of the tool. The operator may elect to underream only specific sections of the well where swelling formations cause stuck drillstrings, or allow full circulation in deactivated mode to clean out sections of the wellbore. RFID tools have a full bore which enables wireline to be run through the reamer. RFID allows for multiple tools to be run in the drill string and activated or deactivated on demand.

Activation is controlled by pumping small tags through the bore of the tool. RFID tags transmit commands to the underreamer as they pass through the tool; an electronic reader embedded in the tool reads the command. All commands and other RFID controller events are stored into memory and may be downloaded after the job is complete.

This paper discusses the benefits and value of RFID activated underreamers. The lab and field test results of the RFID controlled underreamer will be presented.
Reservoir Simulation of Detailed Object-based Models of a Complex Fluvial System
Authors: Gilman James R. , Wang Huabing
Published: October 2011

This paper addresses insights obtained from dynamic simulation of detailed models of low permeability fluvial sandstones in the Williams Fork Formation, Piceance Basin, Colorado. The detailed static models and an overview of the dynamic modeling aspects were decribed previously (Pranter et. al., in press). The static models represent the complex stratigraphic architecture and connectivity of these fluvial sandstones as developed through outcrop analysis while the flow simulation provide a means to understand the dynamic connectivity. The Williams Fork Formation consists of fluvial channel sandstones, crevasse splays, floodplain mudstones, and coals that were deposited by meandering- and braided-river systems. Static connectivity analyses of 3-D outcrop-based architectural-element models have shown how relatively wide sandstone bodies enhance connectivity. The dynamic simulations illustrated in this paper shows that historical performance can be mimicked by considering only point bars, channel bars and marine sandstones (reservoir-quality sandstones) as pay. The reservoir simulations used an integrated approach to create 3D dynamic simulation models by combining detailed static geological, geophysical and petrophysical characterizations. We incorporated and calibrated hydraulic fracture properties at each well to approximate initial productivity, used the characterization process to match hyperbolic decline behavior and then investigated the volume influence of wells and the impact of geologic characterization on performance by predicting longterm gas recovery. These realistic and detailed reservoir models can honor the historical gas rate without applying the assumption of open natural fractures. This work demonstrates that an integrated approach can lead to realistic 3D geologic and dynamic models which are consistent with static data and historical performance. Such models are useful for estimating the impact of complex sandstone connectivity on early and long-time performance including well interference and optimal spacing. The paper also briefly discusses how seismic constraints can lead to more unique descriptions with regard to distributions of multi-story sandstone channels. Such methods combined with detailed geologic models as described here could be used for designing more optimal well locations and optimal spacing in less developed areas in tight gas reservoirs.
Automatic Early Fault Detection for Rod Pump Systems
Authors: Liu S. , Raghavendra C. S. , Liu Y. , Yao K. , Balogun O. , Olabinjo L. , Soma R. , Ivanhoe J. , Smith B. , Seren B. , Lenz T. L. , Dinesh Babu C. G. , Ershaghi I.
Published: October 2011

Typically, rod pump system failures are determined using the dynamometer card which may miss some early warnings. This paper presents a novel approach for early failure detection in rod pump wells using more than 14 parameters that indicate the daily functions of rod pump wells and employs advanced machine learning techniques. Our system recognizes failing, failed as well as normal situations by learning their patterns/signature from historical pump data, that include card area, peak-surface load, minimum-surface load, daily run-time, and production data. These data are automatically pre-processed using expert domain knowledge to reduce noise and to fill-in missing data. Our approach is novel in two ways. First, our machine learning algorithm AdaBNet uses boosting to learn several Bayesian Network models and then combines these models with different weights to form a stronger boosted model. Second, our approach generates this single boosted model that is applicable across all the wells in a field, as opposed to well-specific approaches that generate one model per well. This model detects anomalies, prefailure and failure signals and generates corresponding alerts. Early fault detection in rod pump wells is useful for automatic monitoring of large number of assets remotely, and could be extended to other artificial lift systems. We used a training data set of 12 wells to construct the learning model for the AdaBNet algorithm and tested the algorithm on 426 wells from the same field. The results show that our algorithm detects failures with accuracy higher than 90%. This framework can help field operators not only to remotely recognize and predict failures in advance, but also to help prioritize the available manpower, save significant time, reduce operating expense (OPEX), downtime and lost production. Early fault detection in rod pump systems can allow for proactive maintenance that can delay and even prevent future well failures. The proposed algorithm can enable production engineers remotely detect failures and anomalies before they occur, and assess the situation at control centers before taking any remedial or corrective actions. This approach to using a single model for an entire field is superior to other approaches with individual model for each well.
Innovative CT Abrasive Hydrajetting Perforating Approach in A Complex Saudi Arabian Gas Well Overcomes Initial Inability to Perform A Proppant Fracturing Treatment and Achieves Better Than Expected Results: A Case History
Authors: Nunez Garcia Walter , Solares J. Ricardo , Malik Ataur , Vielma Jose , Chacon Alejandro , Wolfe Craig
Published: October 2011

One of the key components for a successful hydraulic proppant fracturing treatment is an efficient perforating strategy capable of ensuring good communication with the formation while reducing near wellbore pressure losses. It is not unusual to encounter unexpected high fracturing fluid injection pressures and low injectivity conditions in wells requiring stimulation to increase their productivity, due to a variety of reasons including inadequate perforation tunnels. The problem gets compounded further in wells drilled in high pressure and temperature formations, in which performing proppant stimulation treatments poses a considerable challenge.

The general approach used in wells selected for proppant fracturing treatments is to use conventional perforating techniques that create relatively short tunnels with entry holes with a diameter several-fold larger than mean proppant diameter. However, due to formation damage related effects caused by drilling practices or other operational steps long tunnels are frequently required to bypass the near-wellbore damage and connect with the reservoir.

Saudi Aramco has been successfully using hydrajetting technology while stimulating open-hole horizontal wells. However, application of the technique in vertical wells drilled in sandstone reservoirs had been successfully tried only once before its application in Well A.

This paper describes how the inability to perform a proppant fracture treatment in a well drilled in a sandstone reservoir, which had originally been perforated using conventional methodology, was overcome by applying an innovative approach involving the use of hydrajetting technology. The proppant fracture stimulation treatment had to be aborted after very low initial injectivity and abnormally high stress at maximum allowable treating pressure were encountered during the DataFrac diagnostic test. However, after implementing the innovative approach a large size proppant fracturing treatment was successfully performed, and it improved well performance from a gas rate of 0 to 25 MMSCFD at high FWHP. The successful approach provided a viable cost-effective alternative to the conventional methodology, and it has since been applied with equally excellent results in several additional cases.
The Integration of Petrophysical and Formation Tester Data in the Creation of a Petrophysical Model for an Eastern Siberia Oilfield
Authors: Karpekin Y. , Weinheber P. , Abdrakhmanova L. , Tsiklakov A. , Gordeev Y. I. , Maslov S. O.
Published: October 2011

The Verkhnechonskoye oil and gas field in Eastern Siberia produces from a highly complex Precambrian, lower Vendian sandstone. In this reservoir there has been significant post-depositional alteration due to diagenesis, secondary porosity is common and salt, anhydrite and carbonate cementation of the porosity frequently occurs. In short, the reservoir provides substantial petrophysical challenges. In the development of a petrophysical model three specific concerns were noted. Firstly, the effects of the salt-filled pore spaces complicate the determination of porosity and therefore permeability. Secondly, it is difficult to resolve permeability predictions from logs, core and formation testers. Finally, using conventional petrophysics, even with a comprehensive suite of logs and extensive core data, it is difficult to clearly delineate gas-filled porosity from oil-filled porosity and the determination of the gas-oil contact was therefore uncertain.

This paper will discuss how petrophysical data from traditional triple-combo measurements was integrated with NMR measurements, core analysis data and formation tester data including permeabilities from pressure transient analysis (PTA) to produce a coherent and robust petrophysical model for permeability prediction.
The Use of a Wireline Formation Tester with Dual Intake Inflatable Packers to Optimize Fluid Analysis in an Eastern Siberia Heavy Oil Field
Authors: Tsiklakov A. , Weinheber P. , Wichers W. , Zimin S. , Oshmarin R.
Published: October 2011

The Vankor field development in Russia's Eastern Siberia involves the exploitation of moderately viscous oil from medium to low permeability reservoirs. The field is on production from two different layers, both of which have active aquifers and are supported by water injection. Conventional petrophysics in the field can be difficult and fluid typing is often ambiguous. Downhole fluid analysis with wireline formation testers (WFT) is frequently used to assist in the clarification of petrophysical challenges.

However, formation tester operations are not straightforward. Lower permeability and higher oil viscosity means that the WFT probe does not allow sufficient area for fluid to flow. Inflatable dual packer devices are therefore required. The inflatable packer, however, brings its own challenges. With a larger volume of reservoir being investigated longer pump times are required to evacuate invaded filtrate. Additionally, issues associated with the relative permeability of water and heavier oil frequently mean that hundreds of litres of fluid often must be pumped before the fluid typing questions are resolved. In this paper we discuss the implementation of a modified formation tester tool that uses an inflatable packer arrangement configured with dual intake ports. Each of the intake ports is supported by an independent pump and fluid analysis section. Such a configuration offers two benefits. Firstly, the simultaneous operation of two pumps allows the evacuation of larger amounts of fluid in a given time. Secondly, and more importantly, the positioning of the intake ports within the dual packer module allows the tool to take advantage of the density segregation occurring in the packed off interval and to arrive at a clean oil flow much more quickly than a standard configuration. Field examples and lessons learned are provided.
Estimating Drainage-Area Pressure with Flow-After-Flow Testing
Authors: Kabir C. S. , Elgmati M. , Reza Z.
Published: October 2011

Estimating the individual wells’ average drainage-area pressure or pav is cornerstone to any reservoir-management practice. Yet, conventional methods do not always offer reliable solutions to this vexing problem. This study shows that transient flow-after-flow (FAF) testing offers an excellent opportunity to establish pav in a time-lapse mode, when conducted following operational shut downs. Instrumented wells are natural candidates for FAF testing.

The real-time surveillance offers the opportunity to perform rate-transient analysis that results in drainage volume and, consequently, pav. However, gathering quality rate data commensurate with pressure over a long producing period is fraught with uncertainty, which raises questions about the validity of the pav so obtained. In addition, continuous changes in drainageboundary conditions pose modeling challenges with a given reservoir model. Therefore, the independent estimation of pav cannot be overemphasized. This paper presents a theroretical framework for transient FAF testing and also shows a pragmatic approach to handling pressure/rate data incoherence.
Real-Time Long Distance Teaching: An Extensive Evaluation of the Techniques and Student Response of 6 Years of Non-stop Process
Authors: Teodoriu Catalin , Epps Mary Lu , Barrufet Maria A. , Falcone Gioia
Published: October 2011

This paper presents an extensive evaluation of various Distance Learning (DL) and tele-teaching techniques, based on the experience gained over the past 6 years using free software and commercial web-based solutions, and including live participation of DL students.

This paper discusses the advantages and disadvantages of the various tele-teaching options that have been implemented to deliver highly sophisticated petroleum engineering classes to students worldwide from two universities in College Station, Texas (server location) and Clausthal-Zellerfeld, Germany (teacher's location). Based on the enthusiastic students’ feedback, it is clear that they enjoy tele-teaching and learn from it even more than they do from conventional courses. This paper is a follow-up to the papers SPE 134440 and 124748, which were well received by the audience who suggested further investigation into these techniques.
Backpressure Equation for Layered Gas Reservoirs
Authors: Juell Aleksander , Whitson Curtis Hays
Published: October 2011

This paper presents a backpressure equation (BPE) for wells producing from layered gas reservoirs with or without communication. The proposed BPE handles backflow between the layers through the wellbore for non-communicating layered systems, and accurately describes performance of wells experiencing differential depletion.

The proposed multi-layer BPE has the same form as the familiar backpressure equation for single-layer gas reservoirs, where the correct averages are defined for reservoir pressure and backpressure constants.

The BPE is validated against numerical simulation models, as well as field data which include decades of historical production performance and annual shut-in pressures. All numerical models and field data used to validate the BPE are publicly available. This paper gives guidelines on welltest design to quantify reservoir parameters in layered systems, based on systematic studies with numerical simulation models.
Adequate Cementing Solutions for Deepwater Dual-Casing Running System Improves Operational Efficiency When Drilling Tophole Sections in Deepwater Wells
Authors: Moroni N. , Simeone D. , Parrozza F. , Fazio S. , Therond E. , Belleggia E. , Connell R. , Bogaerts M.
Published: October 2011

To improve drilling operation efficiency in the riserless tophole section, a new casing running system was introduced in offshore Angola. In this new system, the hole sections for the conductor and surface casing are drilled in one run, followed by running both casing strings in one trip, requiring a single cement job. This system uses a minimum of one trip in the hole compared with conventional techniques used for running casing and cementing in the riserless phase. The cementation of the dual casing has similar objectives to normal surface casing cementation: stable wellhead with cement returns to seabed, no shallow flow in case of shallow drilling hazards, and good cement integrity at the casing shoe to continue drilling operations with minimum wait-on-cement time.

The cementation of the dual casing is challenging for several reasons: the cement job has to cover two concentric annuli, the cement returns are passing through the unconsolidated formation with a high risk of losses because there is no conductor casing set below the seabed, possible shallow flow, large formation washouts close to the seabed depth, and the requirement to develop sufficient compressive strength in a short period of time at very low temperatures to bear the weight of both casing strings and the wellhead assembly.

In offshore Angola, the casing running system has been used seven times in water depths from 460 and 1450 m. Initial cement design used conventional lightweight extended lead cement with a neat tail and its drawbacks. The use of this cement system caused losses close to the seabed and resulted in an unstable wellhead requiring top-up jobs. Careful engineering and planning between the service company and the operator resulted in the development and execution of two successful cement techniques. The first technique consisted of Low Temperature Optimized Particle Size Distribution Cement, followed by neat tail slurry. Because shallow drilling hazards were present, shallow water flow slurries were designed for the job. The second technique consisted of a foamed lead cement followed by a neat tail slurry. Both cement designs fulfilled the job objectives.

The dual-string running technique, combined with an efficient cementing technique, enabled a 40% time reduction in the riserless phase of the well operations while safely achieving the well integrity objectives.
Acrolein Provides Benefits and Solutions to Offshore Oilfield Production Problems
Authors: Horaska D. D. , San Juan C. M. , Dickinson A. L. , Lear S. L. , Colquhoun A.
Published: October 2011

Offshore production systems can be negatively impacted by numerous problems attributed to bacterial activity, associated hydrogen sulfide (H2S) and biogenic iron sulfides (FexSy), and mercaptan (R-SH) production. Examples of these problems include microbiologically influenced corrosion (MIC), under-deposit corrosion due to FexSy deposition, equipment fouling due to biomass accumulation, impaired oil-water separation leading to poor water quality and overboard oil-in-water problems, and not achieving pipeline specification due to excess H2S and/or R-SH content.

Acrolein provides a distinctive all-in-one chemical solution to resolving these problems. The key to this solution is fourfold: Acrolein scavenges H2S, it scavenges R-SH, it is a potent microbiocide, and it dissolves FexSy.

This paper details the usage of acrolein in the context of an offshore application with respect to the issues and problems unique to an offshore environment. Acrolein treatment programs can provide effective production odor control and achieve pipeline specifications from both an H2S and R-SH scavenging perspective. The unique dual solubility of acrolein in oil and water enables it to penetrate and remove oil-coated FexSy solids and sessile bacteria from production systems. Due to its low minimum inhibitory concentration, acrolein provides cost-effective biocide treatment not only in batch applications but also in continuous treatment programs. Well-established application protocols using a closed delivery system minimize potential chemical exposure, an important HSE consideration. Acrolein's high order of reactivity and biodegradability lends itself well to usage in a sensitive offshore environment.

A series of case histories are presented that highlight the benefits of using acrolein in offshore systems to mitigate related production problems. Multiple benefits can be realized with the application of one product.
Kinetic Cell and Combustion Tube Results for a Central European Crude Oil
Authors: Glatz G. , Hascakir B. , Castanier L. M. , Clemens T. , Kovscek A. R.
Published: October 2011

This paper increases understanding of in-situ combustion (ISC) mechanisms based on experimental results for a Central European crude oil for which ISC has proven to be economically successful. Ramped temperature oxidation (RTO), or so-called kinetics, studies measure the rate of crude-oil oxidation. Similarly, combustion tubes packed with mixtures of sand, clay, water, and hydrocarbon measure our ability to propagate a combustion front. Through the combination of the isoconversional approach for estimation of reaction kinetics (apparent activation energy Ea, Arrhenius constant or pre-exponential factor A) and implementation of combustion tube runs under different conditions, the mechanisms behind the combustion process are elucidated. The results of seven combustion tube runs are presented and discussed in terms of repeatability, effect of grain surface area, effluent gas concentration oscillations, stoichiometry, minimum air flow rate and recovery efficiency. Based on experimental results, critical parameters for field application as well as for simulation are derived (hydrogen/carbon-ratio, air requirements). Opposed to previous publications, the ISC process is described in terms of stoichiometry for the entire tube run, giving insight into development of hydrogen/carbon-ratio and other important parameters over time. This helps to compare, verify, and tune simulation results obtained from commercial simulators. Results obtained point out the exceptional efficiency of ISC in terms of recovery and fuel consumed. Monitoring combustion stoichiometry over time gives an increased insight into flue-gas composition oscillations.
A Real Time Lift Monitoring and Optimization Solution Applied at Chicontepec Field
Authors: Ramirez Narvaez Antonio , Cetkovic Ivan , Lopez Llopiz Mario , Sandoval Hernandez Gilberto , Acosta Héctor Ruben Tobías , Hernández Utrera Francisco , Cobos V. Héctor , Martínez José R.
Published: October 2011

A Real Time Lift Monitoring and Optimization Solution project has been applied at the Chicontepec Field during 2009, implementing an integrated system of acquisition, monitoring and control of real time data allowing engineers and operators to use the information and needed tools to optimize the operation of the asset.

This solution has provide a comprehensive automation system at 350 wells, most of them under Reciprocated Rod Lift Systems with the objective of increases pumping efficiency, reduces well failures, and minimizes downtime. Monitoring rooms installed at the Operational and Service Company allows access and real time information almost to fifteen engineers to all different workgroups. By integrating engineering analysis and design Production operators now can concentrate on solving problems rather than using valuable time searching for them, improving their efficiency by making effective use of their time and enables all members of a production operations team including automation technicians, well analysts, and production engineers to use the same system enabling them to work as a cohesive team. The system infrastructure is build basically by two servers, serial radio communications and well controllers that allows operating and controlling the Reciprocated Rod Lift Systems like a shut down of the equipment.

This can be accomplish due to the intensive training through courses and on site support that has been delivered to the teams, sharing of data and knowledge leads to better design and implements results, increasing oil production and reducing failures. Some of the results obtained during 2009 were the reduction of premature failures due to smart alarms, reduction on the use of digital echometer, inferred production of each well per day and the capability to determine gas consumption per well.
Micro Seismic Monitoring: First Borehole Micro Seismic Job Done in Colombia, Morpho Well
Authors: Garcia Juan G. , Franco Victor H. , Vasquez Cesar , Wills Alejandro
Published: October 2011

Since the inclusion of Micro Seismic technologies in the Barnett Shale, this technology has become one of the most powerful and used tools to monitor the behavior of reservoirs exposed to hydraulic fracturing with non-permanent arrays and also, to detect changes due to injection/production of fluids during long periods of time using permanent arrays.

This paper focus its efforts in non-permanent arrays, which require the use of high resolution seismic tools deployed in the well and anchored to the casing walls to detect micro seismic events produced by induced movement in un-deformed rock or along pre-existing fractures which is in response to the interaction between natural stress directions and equilibriums and those that are being forced on the deformations through stimulation or injection. This paper will present results from the first micro seismic job done in Colombian history, which was performed in December 2010. The results obtained with the implementation of this technology want to provide an image of the zones affected with the injection of fluids, which will allow the operating company to define drainage areas and optimize the location and development of new wells in the field, optimize perforating spacing and location, analyze the containment of the fracture to the interest zone and avoid the migration or the rupture into undesired zones like aquifers, it will also help define optimal injection rates and proppant concentrations. After having a better knowledge of the fracture behavior, stress distribution and production levels, one can think in re-defining drilling strategies and to think the feasibility of highly deviated to horizontal wells; these kinds of decisions had been taken by companies that used micro seismic and were translated in millions of dollars in savings. One of the most notorious examples is the Barnett - Shale, where they moved from vertical wells to a big majority of horizontal wells, which boost the production rates and transformed this field in one of the biggest gas producers in USA; similar steps are being followed in the Marcellus shale and the Haynesville shale in USA, as well as fields in Canada, and India just to mention some.

This paper center is based on results obtained from the first borehole micro-seismic job done in Colombia and will present the conclusions obtained from combining results from different services ran in the well Morpho – 1. Combining the analysis of pressure curves with micro seismic gives us a great idea of how the different fracture types can be observed and also, will help fracture designing teams to better understand and determine the best way to treat rocks.
Selecting Candidate Wells for Refracturing Using Production Data
Authors: Roussel Nicolas P. , Sharma Mukul M.
Published: October 2011

The selection of candidate wells for refracturing is often very difficult based on the information available at the surface. We propose a systematic methodology to allow a field engineer to evaluate a well's potential for refracturing from an analysis of field production data and other reservoir data that is commonly available. We successfully confronted our method to a case study in the Wattenberg field using data from 300 Codell tight gas wells.

The performance of refracturing treatments has been observed to be highly variable in the Wattenberg field (Colorado) with some wells underperforming while others are restored to initial or even higher production rates. Historically, multiple approaches have been taken to select the best candidate wells, including heuristic guidelines, field correlations, and neural networks.

After identifying the physical phenomena that are thought to impact the performance of refracturing operations, we developed five dimensionless groups to quantify them. By choosing a dimensionless approach, we establish refracturing criteria that may be applied to any oil or gas field. One potential motivation for refracturing is the stress reorientation occurring around a fractured well causing the refracture to propagate orthogonally to the initial fracture in under-depleted sections of the reservoir. Numerical simulations of the areal extent of the stress reversal region as well as tiltmeter measurements confirmed the existence of refracture reorientation in the Codell formation. Guidelines for the selection of refracturing candidates were expressed in terms of the potential for stress reorientation, the quality of the initial completion, the initial production decline and the reservoir depletion around the well of interest. Two groups of wells showed the most promise for refracturing: (a) ineffective initial completions with a small initial production decline and (b) long initial fractures in under-depleted reservoirs. The dimensionless groups help us identify such wells and provide quantitative criteria for selection of wells that may be good candidates for refracturing.
Strategies to Minimize Frac Spacing and Stimulate Natural Fractures in Horizontal Completions
Authors: Roussel Nicolas P. , Sharma Mukul M.
Published: October 2011

The opening of a propped transverse fracture in horizontal wells causes a reorientation of stresses in its neighborhood, which in turn affects the direction of propagation of subsequent fractures. This phenomenon, often referred to as stress shadowing, can negatively impact the efficiency of each frac stage. By mapping the angle of stress reorientation and the horizontal deviatoric stress in multi-fractured horizontal wells, we offer some insight on the completion designs that will (a) minimize induced fracture spacing without compromising the efficiency of each frac stage and (b) effectively stimulate natural fractures in the vicinity of the created fracture.

The rapid development of shale gas in North America can be tied to the combination of horizontal drilling and multi-stage fracturing. The spacing between fractures and perforation clusters as well as the ability to stimulate the fractures naturally present in the rock are thought to be major factors in the success of horizontal completions in shale gas reservoirs. The understanding and quantification of the mechanical stress interference generated during the stimulation of horizontal wells is crucial to improving reservoir drainage in shale gas reservoirs

Transverse fractures initiated from a horizontal well may deviate toward or away from the previous fracture depending on the mechanical properties of the reservoir rock, fracture spacing, and the orientation of the previous fracture. Using a numerical model allowing non-transverse fractures (those that deviate from the orthogonal path), we show that some induced fractures propagate into previously stimulated areas during the consecutive fracturing of a Barnett shale well, thus decreasing the reservoir drainage efficiency of the frac treatment. The observed net pressure trend matches field observations during fracturing and microseismic measurements.

The alternate sequencing of transverse fractures as well as multi-lateral completions were recognized to be effective ways to enhance natural fracture stimulation, by allowing fracture stages to experience a smaller stress contrast during propagation. More importantly, it is shown that net fracturing pressure data measured in the field can be used to detect mechanical interference between multiple transverse fractures and optimize fracture spacing for a specific well.
Validating of the Reservoir Connectivity and Compartmentalization with the CO2 Compositional Gradient and Mass Transportation Simulation Concepts
Authors: Daungkaew Saifon , Mullins Oliver , Johan Zailily , Lehne Eric , Zuo Julian , Sinnappu Suresh , Pfeiffer Thomas , Lin Tan Giok , Tunku A Muthalib Tunku Indra , Hong Teh Yat , Rameli Hazwani Bt , Ludwig John T
Published: October 2011

More than 40% of the world's conventional gas reserves are in reservoirs that contain significant amounts of H2S and CO2. The presence of these gases results in a number of challenges for the Field Development Plan (FDP). For a field with multiple fault blocks with unknown fault transmissivity, a key challenge is to understand the field connectivity and compartmentalization which impacts the ability to drain their reserves.

This paper presents a comprehensive study to understand reservoir connectivity in a gas and oil fields located in South East Asia. This particular field has variation of the CO2 even in the same zone ranging from less than 10% to more than 80%wt. A key for production strategy and facility design is to be able to accurately quantify CO2 in each reservoir is. Initially, the CO2 study aimed to quantify the CO2 content for each reservoir using an advanced Downhole Fluid Analyzer (DFA), and then to use the DFA measurement as well as the available PVT data from nearby wells to understand reservoir connectivity through the use of a compositional gradient concept. Reservoir fluids that deviated from the compositional gradient were considered to not be in equilibrium. In addition, the use of a PVT thermodynamic calculation with a non-isothermal solution resulted in a possible identification of the CO2 charging location.

Although the geochemistry study was conducted to understand the source of CO2 and hydrocarbon isotopes, it did not provide a conclusive result of the reservoir connectivity. As expected the hydrocarbon had a different charge source compared to the non hydrocarbon gases. Since the geochemistry study was inconclusive, a mass transportation simulation was performed to understand the reservoir connectivity and this information has had a great impact on understanding the production mechanism of this field.

This paper provides a systematic process to understand the reservoir connectivity by using the integrated reservoir data such as pressure, DFA, PVT fluid properties, geochemistry, as well as the geological and geophysical interpretations of the reservoir. This paper offers an efficient way for reservoir characterization for proper field management for an important hydrocarbon discovery in South East Asia.