bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Stimulation Effectiveness – Field Results in the Haynesville Shale
Authors: Pope C. D. , Palisch T. T. , Lolon E. P. , Dzubin B. A. , Chapman M. A. 
Published: February 2011

Abstract
Effective hydraulic fracturing has become a critical component in the successful development of most unconventional gas reservoirs, including the massive Haynesville Shale. The rig count in the Haynesville currently exceeds 130 active units and is expected to continue to climb. Many hundred horizontal wells have been drilled and completed, and several thousand stages have been hydraulically fractured. With this large and sometimes diverse cross section of wells, best practices have begun to emerge for various aspects of the stimulation design.
This paper focuses on several areas of the completion and hydraulic fracture design in the Haynesville Shale that are identified as critical to the success of this play, including:
The impact of lateral length, number of fracture stages and perf clusters The impact of effective fracture length The impact of fracture conductivity
This paper will review production data from 56 wells completed in close proximity by a single operator to evaluate the impact of fracture design on initial production rates and sustained productivity after six and twelve months. These findings will be compared to reservoir simulator predictions, pressure transient testing, and production data analysis interpretations to evaluate the mechanisms constraining well production.
Readers of this paper who are currently working in the Haynesville will be able to compare their current completion techniques to those presented in the paper. The authors hope this paper will promote a continued dialog on best completion practices among operators in this massive shale play. The findings in this paper may also be used by engineers as a guide for moving up the learning curve in other unconventional plays.
Combining Seismic Models with Realtime LWD Measurements to Reduce Geologic Uncertainty: A Case Study of the Mars A-8 Extended Reach Well
Authors: Weiland Jeff , Cuttitta Matt , Soto Gerard , Wandstrat Matt , Donadieu Brian , Jebutu Segun 
Published: February 2011

Abstract
In January of 2008, Shell began drilling an extended reach exploration well from the Mars tension leg platform (TLP). This was an ambitious undertaking with targets nearly 20,000 ft (6,096 m) away in an unexplored fault block. Because of the high inclination of the borehole and the shallow depth of the objective sands, any geological uncertainty in the targets jeopardized the success of the project.
While surface seismic is used to evaluate potential targets, it lacks the resolution needed to reliably place those targets. Different seismic processing techniques are available, but the validation of each model requires additional information. True vertical depth (TVD) and true vertical thickness (TVT) synthetic ties created from realtime logging data can improve that resolution. By employing a method that uses TVT, the synthetic ties better match the seismic model allowing for updates to the well path and precise placement inside the target. Multiple velocity models are also incorporated to obtain better time-to-depth relationships and to better predict pore pressure anomalies.
In extended reach wells, small issues in the beginning can escalate into more serious problems at total depth. The well path, dogleg severity, and casing shoe placements must be optimized, leaving room for the possibility of changes due to unexpected events. Bottom hole assembly (BHA) design is also a key success factor. Acquiring the needed information in realtime to update the seismic model, while also factoring in tool reliability and planning for shoe-to-shoe performance, is critical. Further, at these high angles, it is important to drill a smooth and continuous borehole to reduce torque and allow for better casing runs.
This paper describes how the geological, mechanical, and economical uncertainties were identified and minimized through well planning and the use of realtime data. Specifically, this paper addresses those uncertainties, associated risks, and the methods to minimize them in the A-8 well.
The authors examine the pre-well work undertaken with the seismic data and how the BHA and well plan were designed to allow for possible changes. In addition, they will discuss how all the data were used to continually update the model and reduce geologic uncertainty as the targets were approached. Answers were provided in time to update the well path, increasing the chances for success, and ultimately meeting the well objectives.
Drilling of Middle-Eastern Reservoir Carbonate Rocks by High Power ND: YAG Laser
Authors: Erfan M.R. , Ahmadi M. , Ashena Rahman , Ashena Rahim , Nazari M. , Roohi A. , Moazeni A. , Moradkhani Mehrdad 
Published: February 2011

Abstract
High power lasers when applied to drilling is potentially capable of reducing the drilling time, improving well performance and exemption from the necessity to remove the cuttings.
In this paper, Rate of Penetration (ROP) and the specific energy (SE) required to remove the rock from Carbonate reservoir rock, Ahvaz#383-9 is measured using the Nd.YAG pulsed laser to identify the prospective laser application for drilling in South of Iran. The three samples selected from each depth and formation were the dry, water and oil saturated. The petrography studies of the rock samples were performed before and after the laser test to analyze any changes in the rock mineralogy and properties. SE was measured with different operational parameters comprising the laser beam and rock properties to detect their effect. This would help us to spot the optimum operational beam parameters with fixed rock properties to be adjusted to obtain minimum SE.
The results show SE increases with increasing laser radiation time and drilling depth non-linearly. SE corresponding to water saturated samples were higher than that of oil saturated and the SE of oil saturated were higher than that of the dry samples. ROP and SE showed to have a nonlinearly inverse relationship.
The optimum operational parameters determined, can help optimize the laser application in regards to obtaining the minimum SE. Future laser rock mechanical laser simulation softwares can be developed based on the experimental approach.
Qualifying Seismic as a Reliable Technology —An Example of Downdip Water Contact Location
Authors: Sidle R. E. , Lee W. J. 
Published: February 2011

Abstract
The term "reliable technology" was added to the lexicon of oil and gas reserves estimation with the updated regulations published by the US Securities and Exchange Commission (SEC) in late 2008. A previous paper by the co-authors (2010), SPE 129689, described an approach to the demonstration that a technology satisfied the criteria of a reliable technology. This paper builds on the use of the scientific method, as described in the previous paper, by examining a real-life example of seismic interpretation to define water contacts downdip of hydrocarbon column penetrations.
Complex technologies, such as seismic, require careful and detailed calibration and testing to demonstrate the consistency and repeatability needed to qualify as a reliable technology. However, this complexity need not preclude that technology from use as reliable. Proper analysis of the science behind the technology and testing to demonstrate those circumstances which allow reliable conclusions from the technology will permit even a complex technology to be qualified as acceptable.
The example used is from the Gulf of Mexico (GoM) Deepwater. It gives the results from several turbidite sand reservoirs in multiple fields to demonstrate the conditions under which certain seismic can be shown as reliable. The learnings from these applications allow the development of a "reliability qualification checklist" which defines the conditions under which the seismic data are definitive. Then it describes the final testing of the "reliable data" to determine when a seismically interpreted water contact is sufficiently conclusive to be reasonably certain.
This paper will provide a useful description of how the qualification of a technology can be planned, tested and conclusions drawn. It will provide examples of constraints that develop from the theoretical analysis and testing results and show how these constraints can be incorporated into a set of limitations on the application of the technology. While certain elements of the technology are discussed in this paper, it is not the authors’ intent to provide an exhaustive description of the seismic theory and methods used for this example. Rather, the paper will focus on the reliability demonstration process.
Experimental Studies on the Effect of Mechanical Cleaning Devices on Annular Cuttings Concentration and Applications for Optimizing ERD Systems
Authors: Ahmed Ramadan , Sagheer Munawar , Takach Nicholas , Majidi Reza , Yu Mengjiao , Miska Stefan , Rohart Christophe , Boulet Jean 
Published: February 2011

Abstract
In horizontal and highly deviated portions of an Extended Reach Drilling (ERD) well, cuttings beds form on the low-side of the annulus. The bed partially blocks the annulus resulting in excessive pressure loss and a higher equivalent circulating density (ECD) that is exacerbated by the increase in length of the annulus. This condition limits hole-cleaning capabilities. As a result, selecting favorable drilling parameters is not always sufficient to overcome the hole cleaning problem. Recently, the use of downhole Mechanical Cleaning Devices (MCDs) has been introduced to the industry to mitigate the problem without inducing excessive ECD. Although the use of these tools is increasing, very limited studies have been conducted to optimize their performance.
This paper presents results of an experimental study that was carried out to evaluate cuttings removal efficiency of MCDs and applications of MCDs for optimizing ERD systems. Experiments were carried out in a large-scale flow loop that has an 8-inch transparent test section. Three different drillpipe sizes were considered in the investigation. The Taguchi approach was implemented to reduce the number of experiments while covering the most relevant parameters such as flow rate, ROP, diameter ratio, tool design and drillpipe rotation speed. For each test, the amount of cuttings accumulated in the test section was determined from weight measurements. Results indicate that the tools significantly reduce the amount of cuttings in the annulus, especially around the MCDs, compared to locations where there is no tool.
Experimental results were evaluated to obtain the overall effect of operating parameters on annular cuttings concentration and develop correlations. The results show that the flow rate and inclination angle have the most significant impact. The correlations are useful to develop an analytical model for designing and optimizing drilling systems with MCDs, either in terms of operating parameters or drillstring design.
Field Application of a Water-Based Consolidation System for Remediation of Proppant Flowback
Authors: Cooper J. C. , Nguyen P. D. , Magill D. 
Published: February 2011

Abstract
Post-stimulation proppant-flowback problems have been a major issue in both conventional and unconventional reservoirs. In coalbed methane-gas (CBM) wells that use pumps and plungers to dewater coal, proppant flowback with produced fluid could lead to well downtime because the pumps can get sanded off. This is costly and challenges well economics because losing production and replacing the pumps repeatedly can be expensive. A low-cost solution to this uncontrolled sand production is to clean the well with a workover rig or coiled tubing (CT), identify the zone (or zones) from which the proppant is being produced, isolate the zone (or zones), and pump a remedial proppant flowback-control treatment. Two types of proppant-consolidation remedial-treatment fluids have been successfully used—one is the low-viscosity, solvent-based curable resin, and the other is a new, water-based consolidation system.
A water-based consolidation system was successfully developed to overcome the operational, safety, and fluid-compatibility issues that most current solvent-based resins experience during field treatments. This paper presents the results of laboratory development and field testing of this consolidation system for proppant flowback. Extensive laboratory testing has indicated that an optimum concentration of coating is necessary to maximize the bonding between proppant grains. This allows the proppant pack to withstand high production flow rates and to overcome the effects of stress cycling while minimizing any reduction in its permeability. Field-study results in both sandstone and CBM reservoirs showed that the water-based consolidation system was successfully applied in treating proppant and formation solids in the near-wellbore region to lock them in place without damaging production flow paths. In these field tests, intervals in excess of 300 ft were treated effectively with the bullhead-squeeze method using consolidation treatment fluids that were foamed to a quality of 75% or higher to aid in diverting treatment fluids and extending treatment volumes.
The new system uses small treatment volumes to impart excellent consolidation properties, while at the same time retaining formation permeability. This makes the treatment system simple to deploy and economically viable. In addition to providing the results, this work discusses the criteria for identifying remedial candidates, optimal placement procedures, and the lessons learned from these treatments.
Dealing with Risk Analysis for Integrated Asset Modelling
Authors: Binda A. , Giliberti S. , Preti A. , Rossi R. 
Published: February 2011

Abstract
The evaluation of the risk associated to a development plan taking into account reservoir uncertainty has become a standard procedure. The integrated dynamic simulation of different assets considering mutual dependencies due to the production network is nowadays a standard procedure too. Integrated Asset Models (IAM) are usually simulated with a deterministic approach (one production profile for each network scenario). A methodological approach to take into account uncertainties together with different development scenarios (network and pipeline characteristics, infill wells, work-over...) is described in this paper.
Reservoir numerical models have to be simplified (material balance models instead of full 3D simulations) to manage probabilistic simulations directly in the network facility model.
The main phases of the methodology are:
– Understanding of the asset and its model – Definition and evaluation of reservoirs and asset uncertainties – Simplification of full 3D reservoir models with material balance – Montecarlo simulation via spreadsheet – Statistical analysis of the results
An easy interface link has been developed to manage input and output in an uncertainty environment. The IAM is simulated by applying the standard software used in the company. The interface is able to set as uncertainty any input data defined in the models.
This work-flow was applied on a dry gas offshore asset, which exploits many reservoirs (including multi-stacked sands) tied back to a central processing facility through a common pipeline network.
The applied methodology proved to be manageable in terms of CPU time, effective and reliable.
Openhole Gravel-Pack Case Histories in Wells Drilled With a Synthetic Mud: Successful Implementation of an Alternative Method in Oyo Field, Nigeria
Authors: Ripa G. , Rossi M. , Staltari D. , Ilobi M. , Lawal T. , Beldongar M. , Douglas T. , Wassouf P. , Jones A. , Parlar M. 
Published: February 2011

Abstract
Openhole gravel packing is a popular completion technique in challenging, high transmissibility reservoirs. Many of such wells are drilled with synthetic fluids and completed with either a single- or a two-trip technique.
In single trip approaches, the entire wellbore is displaced to water-base fluids before running screens and subsequent gravel packing. Although successful in some cases, this technique has been problematic in reactive shale environments, due to problems in screen installation to target depth, resulting from shale swelling and/or collapse. Such problems led operators to a two-trip approach, where a predrilled liner is installed in synthetic-base mud (SBM), displacements performed to water-base fluids and the screens are run in solids-free water-base fluids environment, followed by gravel packing. In recent years, another approach was introduced, in which the displacements to water-base fluids are performed after the screens are installed in conditioned mud and the packer is set, followed by gravel packing with a water-base fluid. Although this approach eliminates the difficulties associated with screen installation as well as allowing a single-trip completion (no predrilled liner), it cannot be used in cases where conditioning is impractical.
In this paper, we present case histories, where screens were installed after the openhole was displaced to a solids-free SBM and cased hole to completion brine, and gravel packing was performed using a water-base carrier fluid. This approach provides a cost-effective alternative to displacement of the entire wellbore to solids-free SBM as well as eliminating the risk of screen plugging, and was successfully implemented on two oil producers in Oyo field. Details of design, execution and evaluation for drilling and completion stages, as well as well productivity measures are provided, along with a discussion of a continuous circulation device successfully used during drilling.
Cementing In Unconsolidated Sand West Delta Deep Marine Fields, A Case History
Authors: Farag Hossam , Shaaban Sherif , Eid Ramy , Hesketh Mark 
Published: February 2011

Abstract
Past experiences in the Sapphire location in the Mediterranean, have witnessed wells which suffered damage in various storms; being pulled over to at least 2.5° inclination by the attached riser. With the increasing rental rates for semi-submersibles, the challenge was to cement the conductor casing in highly unconsolidated shallow sands, while eliminating the need for time consuming Top-up jobs, causing rig time loss with hefty rig rates.
The objective was to formulate an unconventional, quick-setting light weight cement slurry, with high compressive strength, thus providing adequate axial capacity for landed-off casing weights., while preventing cement subsidence after placement. Extensive Laboratory testing and Field results indicating the rate of success of this technique will be covered within the scope of this paper.
In this paper, the authors will discuss the cause of the problem, the approach taken forth by all participating parties and the overall approach taken to achieve success in minimizing rig time lost and achieve axial support.
This technique can be applicable for cementing conductor casing in most deep water environments, where very low temperatures are experienced at seabed. The field verified rate of success was mainly attributed to proper data collection and proper testing procedures.
The Development of Subsea Boosting Capabilities for Deepwater Perdido and BC-10 Assets
Authors: Gilyard Dustan , Brookbank Earl B. 
Published: February 2011

Abstract
Significant advancements in deepwater subsea boosting technology, operations, and surveillance are represented by two Shell world-class developments: Perdido in the Gulf of Mexico (that will begin production in 2010) and BC-10 offshore Brazil (on stream since July 2009). These novel projects continue the long tradition of Shell's leadership in the challenging deepwater environment by development and application of a novel seafloor boosting system.
The subsea boosting system utilized by both the Perdido and BC-10 assets for increased ultimate recovery and higher production rates is based on the application of electric submersible pumps (ESP) located in a shallow seafloor caisson. These caissons collect production fluids from the manifolded subsea wells and prevent significant loss of ESP performance due to excessive gas production by passive liquid/gas separation.
Extensive testing and qualification of the subsea boosting system was undertaken prior to final configuration selection including construction of the world's only 1500-hp ESP test facility capable of controlling multi-phase fluid viscosities and temperatures. A comprehensive suite of tests was performed in conjunction with Baker Hughes Centrilift replicating the expected conditions and performance requirements for both deepwater assets. This paper describes the subsea boosting system maturity process, and discusses the current status of each development and related key learnings.
Pushing Portland Cement Beyond The Norm Of Extreme High Temperature
Authors: Doherty Dale R. , Brandl Andreas 
Published: February 2011

Abstract
For a recent project in Australia, Portland cement was modified to withstand contact with temperatures above 800 °C. This High Temperature (HT) cement system is applied to cement casing strings used as injection and production wells in a process known as Underground Coal Gasification (UCG). In its simplest form, this process involves drilling a production well and an injector well into an existing coal seam. Once drilling and cementing of the wells are complete the coal is ignited underground, and air and water are then introduced through an injector well. The air reforms with the combustion materials and forms a synthesis gas (syngas) containing carbon monoxide, hydrogen and methane (as a minor component), that moves under pressure through the coal seam to the production well, where it travels uphole to the downstream facility. Since coal typically resides at shallow depths, it was necessary to have cement that would set at relatively low bottomhole static temperatures of less than 39 °C and have the ability to withstand the extreme temperatures of the advancing combustion front, which can exceed 800 °C.
Portland cement with a silica source has been used in geothermal wells in which production temperatures can reach 380 °C or more, but recent testing showed that it can completely disintegrate around 450 °C. The final HT cement system design easily tolerates the elevated dry temperatures at the combustion front and maintains compressive strength in normal API compressive strength (CS) tests at 350 – 450 °C. The slurry mixes and pumps in the field as one would expect any slurry properly prepared to do while following API methods. Fluid loss control was adjusted with common liquid additives. Since the welfare of our planet is dependent on our ability to develop more environmentally friendly alternatives, the UCG process may become the preferred method to extract the energy contained within coal. The new HT cement system design enables a cost- efficient, logistically simple cementing method/material for this application where none existed previously.