bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Application of High-Density Elastic Cements to Solve HPHT Challenges in South Texas: The Success Story
Authors: Wray Barry , Bedford David , Leotaud Lennox , Hunter Bill 
Published: October 2009

Abstract
Well cementing operations in south Texas tend to present a number of challenges to those responsible for constructing oil and gas wells. For instance, the temperatures and pressures at which the cement needs to be placed can be extreme, routinely exceeding bottomhole static temperatures of 300°F and pore pressures requiring fluid densities of 17 lbm/gal or greater to maintain well control. These extreme conditions can present challenges not only during placement of the cement slurry in the wellbore, but also later to the set cement sheath during the life of the well.
To effectively meet these challenges, well operators in south Texas have been using high-density cements that have been mechanically modified so the set cement will be more elastic and resilient. Advanced diagnostic software is used to predict well situations where these cements are required.
Currently, high-density elastic cements (HDEC) have been placed in more than 40 wells in southern Texas and the use of these sealants combined with diagnostic software has become routine.
This paper discusses the challenges presented when cementing high-temperature, high-pressure (HTHP) wells in south Texas, then details the successful best practice life-of-the-well solutions that have been applied by highlighting two representative examples.
The purpose of this paper is to help assist those tasked with the construction of HTHP wells to achieve their objectives safely and reliably and deliver zonal isolation that can be expected to last for the life of the well.
Environmental Considerations of Modern Shale Gas Development
Authors: Arthur J. Daniel , Bohm Brian , Cornue David 
Published: October 2009

Abstract
The Barnett Shale play of the Ft. Worth Basin has sparked considerable investment in the Woodford, Fayetteville, Haynesville, and Marcellus Shales, as well as in other shale plays. Key to developing these unconventional natural gas resources is the management of water and other environmental issues facing the developers active in these plays including water availability, water handling/transport, hydraulic fracturing and management of fracturing fluids, water disposal, urban drilling, NORM, and other environmental considerations. This paper will discuss these environmental considerations and challenges related to modern shale gas development in several major plays within the United States, as well as the potential impacts of the expanding public concern regarding shale gas development, and practices and solutions implemented to facilitate ongoing development.
An Alternative Method of Dealing With Pressure: Friction Reducer for Water Packing of Long Horizontal Open Holes in Low-Fracturing-Gradient Environments
Authors: Baser B. , Shenoy S. , Gadiyar B. , Jain S. , Parlar M. 
Published: October 2009

Abstract
Water packing is the most commonly used gravel packing technique for openhole horizontal completions. With this technique, the packing of a horizontal well occurs through two sequential events, called the a-wave and the β-wave. Because the carrier fluid is diverted into and must travel through the narrow annulus between the screen base-pipe and the wash-pipe all the way to the toe, pressure builds up steadily during the β-wave as the packing proceeds from toe to heel, due to high friction pressures in that annulus. This rise in pressure may result in exceeding the fracturing pressure of the reservoir, which in turn causes a premature screenout and an incomplete gravel pack.
This is a well known problem, which in the past often limited the horizontal well length that can be gravel packed in many deepwater developments, due to narrow operating window. Today, various solutions are available to solve this problem, including mechanical solutions that create a short cut for fluid returns, and the use of light weight gravel which allows pumping at lower rates without having to worry about gravel settling in the work string but still have a a-wave height that will cover the screens.
In this paper, we present an alternative method of dealing with the pressure rise during the β-wave, reducing the friction pressures through addition of a friction reducer to brine carrier fluid. We first detail the laboratory scale experiments used for screening of many additives considered, including laboratory scale friction pressure measurements, compatibility with high density brines, gravel settling, formation and gravel pack damage. We then discuss the results from full scale friction tests conducted in pipe and annular geometries, using the best candidate friction reducer selected based on laboratory tests. The results indicate that a drag reduction of 40 to 50% is attained with an environmentally friendly friction reducer, with retained permeability of about 90%, and with minimal to no impact on gravel settling and thus a-wave height.
A Study on Peer Assessment of Teamwork Projects in Undergraduate Petroleum Engineering Education
Authors: Cinar Yildiray , Bilgin Ayse A. 
Published: October 2009

Abstract
This paper presents an analysis of the peer assessment data collected for assessing teamwork projects assigned in four petroleum engineering courses offered at the University of New South Wales. Term projects were given to 22 groups composing from 4 to 7 students. Each team was asked to search for an open-ended discipline-specific problem, formulate the problem, provide solutions to the problem and present the outcome through a technical report and an oral presentation. An assessment value of 30% of the total was allocated to the projects. The teamwork performance, technical report, and oral presentation were assessed to determine the total marks for the groups. A peer assessment survey was then undertaken with the main aim to derive the individual marks. The peer assessment was based on logistics, leadership, group dynamics, intellectual and research/writing/editing.
The collected data represents a wide range of groups composed of various student profiles which include international and local students, male and female students. The analysis emphasizes the peer assessment as a viable tool for evaluating the individual contributions to a discipline-specific teamwork project. However, the human bias must be adequately adjusted for fair assessments. The study demonstrates that poorly performing students in the groups can be identified by utilising peer assessment. However, this also requires the judgement of the lecturer based on the observation of team members through weekly meetings and the minutes taken during the team meetings. The international students seemed to be more generous than the local peers in the assessment. It was determined that a significant number of students (about 40%) gave the highest marks to peers for all assessment criteria. In four groups out of 22 groups, all team members gave the highest rates to each other for all criteria, which made the peer assessment entirely useless. Three of these four groups were composed of international students only. All these observations underline the necessity to train the students for the importance of the peer assessment.
Coupled Thermo-poro-mechanical Effects on Borehole Stability
Authors: Zhai Zongyu , Zaki Karim S. , Marinello Steve , Abou-Sayed Ahmed 
Published: October 2009

Abstract
A new model and numerical scheme are developed to study the effects of poro-elasticity and thermo-elasticity on borehole stability. The poro-thermo-mechanical model integrates the effects of both thermal and hydraulic diffusion in determining the effects of the drilling fluid and mud weight on the borehole system.
Thermal diffusion into shale formations occurs quicker than hydraulic diffusion, thereby dominating pore pressure changes during early time. The thermal differential can affect shale stability in two ways: The differential-driven thermal diffusion induces additional pore pressure that adds to the poro-elastic stress change near wellbore.The thermal differential directly induces a change in rock stresses.
Previous publications have adequately investigated and addressed the second of the two issues. The current work attempts to model and assess the impact of the first mechanism.
In the model, thermal diffusion is coupled with hydraulic diffusion to obtain the pore pressure distribution reflecting the cumulative impact. The generated poro-elastic and thermo-elastic stresses are obtained by solving equilibrium equations utilizing superposition.
A field case is included in this paper and shown that the thermo-elasticity adversely would affect the borehole stability.
A Comprehensive Study of Sanding Rate From a Gas Field: From Reservoir, Completion, Production, to Surface Facilities
Authors: Han Gang , Shepstone Keith , Harmawan Iwan , Er Ufuk , Jusoh Hasni , Lin Lim Sue , Pringle Dave , Koya Rani , Carney Stephen , Barker Larry , Morita Nobuo , Papamichos Euripides , Cerasi Pierre , Sayers Colin , Heiland Juliane , Bruno Mike , Diessl Julia 
Published: October 2009

AbstractAn offshore gas field has been producing sand for a few years. Sand production has been closely monitored through acoustic flowline devices and a sand collection system installed on the platforms. Observation of sand production has triggered evaluation of whether to install surface desanders or complete future wells with downhole sand control. This evaluation requires a prediction of sanding rate over the reservoir life. The possibility of providing downhole sand control on existing wells was also evaluated in separate studies.Predicting sanding rate, particularly for gas fields, has been historically challenging, mainly because of the sporadic nature of sand production, inadequate quantification of fundamental physics, and lack of representative lab tests, and reliable field calibration. To tackle these challenges, four studies have been designed and executed, including 1) the development of a reliable log-based rock strength estimate; 2) the prediction of sanding rate over the reservoir life for a conservative well condition; 3) the evaluation of sand particle transport from the reservoir to the surface facilities; and 4) the estimate of potential erosion of platform facilities.The sanding rate prediction is based on extensive laboratory tests of four carefully selected whole cores, with gas and water flow. It has then been validated by field monitoring data from an acoustic flowline device on each producer and a sand collection system on the platforms. The studies have provided a prediction of future sand production, how much of the produced sand will be seen at the surface (and therefore how much of it will fall into the rathole), how fast various components of the surface facility will erode over the field life, and what will be the optimal completion strategy for sand control should it become necessary. They have provided input to an integrated evaluation of completion design, reservoir management, platform configuration, and field economics.
Production Optimization of Horizontal Wells in a Heavy-Oil Field
Authors: Qinghong Y. , Lizhen G. , Peng Z. , Thomas T. , He G. , Li X. , Tong Y. 
Published: October 2009

Abstract
In this paper we detail the work done in production optimization of a heavy oil field by detailed analysis of the geological, reservoir and production data with the intent to optimize the production performance of the horizontal wells in the field. We study the geological, reservoir and production factors, like extent and thickness of barriers to flow, net thickness cut off, water flow mechanisms in the reservoir, production history, production diagnostics and finally the placement criteria of new horizontal wells in order to optimize the field production.
A combination of geological, reservoir and production factors are considered to study the reservoir flow mechanisms and creation of diagnostic plots to study the well inflow mechanisms. The well inflow findings are substantiated by streamlines which track fluid inflow. The outcomes of the above process provides the engineer a comprehensive set of tools to monitor, diagnose and take appropriate actions for production optimization of the horizontal wells.
Through the work done we were able to identify the reservoir thickness cut off, critical rate, optimum drawdown, length of horizontal wells and well window for optimum production and delaying water coning which compromises optimal production. The water inflow mechanisms were validated by using streamlines for the fluid tracking and hence recommend appropriate remedial actions with greater confidence. The approaches taken towards production optimization were different for the bottom water and edge water reservoirs as is detailed in this study. The paper details techniques for production optimization in heavy oil settings.
It also focuses on the remedial actions to be performed once the reservoir and well inflow mechanisms have been identified.
Whipstock-and-Inflatable Packer Combination Decreases Openhole Sidetracking Costs in Central Arkansas
Authors: Broussard Andre N. , Templeton Garry W. , Travis Deck 
Published: October 2009

Abstract
Traditional openhole sidetracking operations involve time-drilling off of a balanced cement plug or drilling off of a whipstock cemented in place. The use of cement in these operations can be cost prohibitive, considering the cost of mobilizing a cement unit, time spent waiting for cement to set up (with rig and associated rental equipment on standby), and time spent drilling off of the cement plug or cemented whipstock. Water-sensitive formations can further complicate the sidetracking operation that incorporates cement. In addition, the initial attempt to time-drill off of a cement plug is not always successful, and multiple attempts may be required before a successful sidetrack has been achieved. A cement-in-place whipstock, while typically more consistent in achieving a sidetrack, limits the sidetrack depth to the bottom of the original well. This paper introduces the combination of whipstock and inflatable packer technologies, deployed together in one trip, to effectively sidetrack a well at any depth, without the use of cement. The paper discusses conventional openhole sidetracking methods and compares them with the whipstock-inflatable packer combination. The paper includes case histories taken from recovery maximization efforts in the Fayetteville Shale gas play and shows that using openhole whipstocks anchored on inflatable packers saved time and decreased overall sidetracking costs over a 60-well evaluation period. Finally, the paper also discusses lessons learned over the course of the project and limitations of the system.
The applications of this system include a wide range of openhole sidetrack drilling operations such as sidetracking a well obstruction, correcting directional azimuth, and targeting a pay zone uphole from the original depth of the well.
The analysis data for this paper come from daily drilling reports on actual wells in the Fayetteville Shale gas play. Data taken from wells using conventional techniques are compared to data taken from wells using the whipstock-inflatable packer combination. Cost reductions are correlated directly back to these drilling reports.
This paper shows that using the whipstock-inflatable packer combination saves time and money and enables more consistent sidetracking times.
Development and Field Application of a Novel Non-acid Calcium Naphthenate Inhibitor
Authors: Debord Justin , Srivastava Piyush 
Published: October 2009

Abstract
Current state of the art for treating calcium naphthenates requires addition of large doses of acid to the production fluids. Although effective in dissolving deposits, acid treatments result in increased corrosion in production equipment, decreased oil quality and increased transport and HSE costs. Consequently, an opportunity exists for the development of non-acid inhibitors to prevent calcium naphthenate formation without the drawbacks encountered with acid treatment. In this account, we report on the discovery and development of molecules that, when injected into a production stream, prevent the formation of large scale calcium naphthenate deposits. As a result, these molecules allow for treatment of calcium naphthenate deposits without treatment with large acid dosages. The purification scheme for naphthenic acids and a novel screening test method capable of selecting highly active naphthenate inhibitors will be detailed as well as field testing results in which no deposits formed and excellent water quality was obtained.
Analysis of Transient Data During Relative Permeability Measurement Using Steady State Technique
Authors: Fassihi M. R. , Potter Gary 
Published: October 2009

Abstract
There have been numerous papers discussing the advantages and disadvantages of Steady State versus Unsteady State Relative Permeability tests. But, there have been little discussion about the interrelationships between these two procedures. This paper shows how the transient data (pressure drop and saturation changes) during steady state tests can be used to arrive at relative permeability data and, thus, provide coverage for the full saturation domain. The transients occur after injecting at a new water-oil ratio (or gas-oil ratio) begins and before saturations along the core are equilibrated. A numerical simulator was used to model the steady state method. Injection of water and oil was simulated at different water-oil ratios (WOR) in a one-dimensional model. Both the constant injection rate (CIR) and the constant pressure drop (CPD) cases were simulated. The pressure drop and the fluid injection and production data during the transient periods (before stabilization at the next steady state point) were analyzed. These data closely matched the actual relative permeability curves. The new method was further tested by using actual laboratory measured data. The close agreement between the estimated relative permeability data based on transients with those based on steady state suggests the applicability of this new technique to any system. Thus, by using this technique, it should be possible to reduce the time required to conduct a Steady State tests by running fewer WOR (or GOR) cycles.
The Quest to Understand ESP Performance and Reliability at 220°C Ambient and Beyond
Authors: Noonan S. G. , Dowling M. , Klaczek W. , Piers K. 
Published: October 2009

Abstract
ConocoPhillips has been on a quest for a high-volume artificial lift system that will operate reliably in a 250°C (482°F) downhole environment. This paper will describe the testing and results of a high-temperature electric submersible pump (ESP) system in a flow loop built to validate downhole equipment for thermal applications, primarily for steam assisted gravity drainage (SAGD) developments. What makes this test program unique from previous tests is the longer duration (4+ weeks), the range of fluid temperatures (90°C to 245°C [194°F to 473°F]), and the type and volume of data collected. One of the key parameters monitored and documented was the internal motor winding temperature, which has been used to validate and calibrate a simulator for predicting motor performance in thermal environments.
Saving Expensive Offshore Deepwater Rig Time by Modeling Accurate Subsea/Subsea-Floor Temperature Modeling for Cementing Operations
Authors: Tahmourpour Farzad , Quinton Chris 
Published: October 2009

Abstract
Accurate temperature modeling on an offshore deepwater well or potentially any other type of well can result in reduced, nonproductive time (NPT) attributed to waiting on cement (WOC) time. Understanding the downhole temperature behavior and heat recovery during the static time after placement of cement slurry can provide an opportunity to minimize WOC-time for compressive-strength development. Drilling engineers encounter a variety of requirements by regulatory agencies across the globe concerning cementing operations. Although the regulatory-agency guidelines and expectations in many cases are detailed and challenging, the operational requirement and cost-saving prospects by operators go beyond some of these recommended/required expectations. Almost any optimization that can expedite commencement of the drilling operation after a cement job (for example, drilling, completing, moving rig) should improve the cost-effectiveness of the drilling program. Water temperature gradient profiles from sea surface to seabed through shallow formations below the seabed exhibit diverse characteristics in different fields. An accurate bottomhole static temperature (BHST), or the undisturbed bottomhole temperature (BHT) and understanding the bottomhole circulating temperature (BHCT) behavior is a crucial factor to success of deepwater field developments. This paper will discuss how best practices in combination with optimized downhole temperature modeling can potentially reduce the number of hours in WOC-time without introducing any additional risk factors into the cementing/drilling operations. Calculating accurate downhole temperature and pressure profiles, which are also used for pipe-body movement and casing-and tubing-load analysis, assists cementing, drilling, and completion engineers to produce highly effective solutions.
Properties of Tight Gas Sand From Digital Images
Authors: Metz Mike , Briceno Gabriela , Fang Qian , Diaz Elizabeth , Grader Avrami , Dvorkin Jack 
Published: October 2009

Abstract
Basin-centered gas deposits are abundant in North America. Recently, such reservoirs have become attractive exploration and development targets because they contain vast domestic deposits of natural fuel. A key property required to plan and optimize production in these reservoirs is permeability.
The latter is notoriously difficult to measure in a physical laboratory. Extremely low and often disconnected porosity results in small permeability, often in the nano-Darcy domain. This makes the standard steady-state flow approach virtually impossible to implement and calls for such intricate and lengthy techniques as pulse-decay flow measurement. An alternative to a physical measurement is a numerical simulation of fluid flow in a 3D digital pore space accurately imaged by high-resolution CT scanning.
We present an example of this digital technique for two samples from the Williams Fork formation in Colorado Basin from one well drilled by Occidental Petroleum with the total porosity ranging from 0.01 to 0.10.
The porosity of the first sample was about 0.08. It was dominated by fairly large pores connected by narrow conduits. This pore space was successfully imaged in a micro-CT machine with a voxel resolution of 2.2 microns. The simulated permeability was in the 1 to 5 mD range. The formation factor ranged from 600 to 2,000.
The pore space of the second sample was not discernible at the micro-CT resolution. It was imaged in a nano-CT machine with a voxel resolution of 0.065 microns. Disconnected spherical pores of approximately 1 micron in size were discovered. These pores were predominantly located within calcite crystals, presumably due to secondary dissolution of carbonate inclusions.