bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Salt-Tolerant Friction Reducer for Coiled-Tubing Applications in Unconventional Shale Formations
Authors: Lindsay S. D. , McNeil F. , Sackash M. J. , Bryant J. E. 
Published: September 2011

Abstract
Wells in the oil-and-gas industry continue to be drilled to deeper depths. These wells present complex challenges for completion and intervention operations because operators demand the same level of performance achieved on shallower wells while providing a cost-effective and safe solution.
The size of coiled tubing (CT) deployed in deep-reach wells is maximized to achieve a greater level of performance and operational efficiency, while reducing the pressure requirements of equipment. However, weight restrictions, reel capacity, depth, and trajectory of the well can limit the size of CT that can be used.
Using a new cationic polymer friction reducer allowed CT operations to achieve higher rates and velocities while maintaining hydrostatic pressure and lowering surface-treating pressures. The friction reducer has the following attributes: It is salt tolerant, which enables a wider scope of use.Effective at low concentrations.Easily mixed on-the-fly.Compatible with nonionic additives.Can be used up to 200°F.Compatible with shale formations.Extremely rapid hydration.Created for use with water-based fracturing fluids in unconventional shale formations.Gives the customer the ability to reuse flowback and produced water without damage to the formation or addition of fresh water.
This paper describes the new friction reducer and the benefits of using it in unconventional shale formations. Also included is a case history to demonstrate the success of the system in CT drillouts. These field trials provided data to confirm the following benefits. A 25% treating-pressure reduction was achieved; 20% was predicted using an existing friction reducer.Using a friction reducer lowers pumping pressure and hydraulic-horsepower requirements.The system enables increased pumping rates, lowered surface-treating pressure, and higher velocities.Cost savings were achieved and and value was added to the operator.
Well Integrity Analysis in Gulf of Mexico Wells Using Passive Ultrasonic Leak Detection Method
Authors: Johns J. E. , Aloisio F. , Mayfield D. R. 
Published: September 2011

Abstract
Well integrity management presents a wide variety of challenges for the industry today. With aging fields and more complex completion techniques coming into play, more efficient methods of well diagnostics and remediation are demanded. In the GOM, 45% of the wells have sustained casing pressure; therefore, the importance of having a resource that can provide an effective, accurate method of leak detection is abundantly clear.
Typical methods of leak detection today include the use of spinners, temperature tools and noise logs. Mechanical means such as calipers and isolation packers are also employed. While effective for larger leaks, these methods can produce nebulous results with smaller leaks and can be time consuming.
The frequency spectrum a leak produces is a function of differential pressure, leak magnitude, and leak geometry. These properties determine whether the frequency is audible, ultrasonic, or both. Typically, smaller volume leaks with a relatively high differential pressure will generate an ultrasonic signal. Based on this premise, an ultrasonic logging tool was developed and proven that detects frequency spectrums typically produced by leaks. The tool has a series of band pass filters which remove virtually all audible noise associated with tool movement, allowing continuous logging. Because ultrasonic energy will pass through compressed gas and steel, the tool can detect leaks in secondary barriers as well. Further, as ultrasonic energy attenuates quickly, the tool locates leaks with a high degree of accuracy. Using this tool, leaks as small as 0.005 gpm have been quickly located with an accuracy of a foot or less.
This paper will describe a down-hole ultrasonic leak detection tool and provide case histories of where the ultrasonic leak detection tool was used to find leaks that other methods were unable to locate. A comparison of the results from conventional leak detection methods will be discussed as well.
Effect of the Number and Length of Zonal Isolations on Pressure Behavior of Horizontal Wells
Authors: Al Rbeawi S. , Tiab D. 
Published: September 2011

Abstract
Horizontal wells with multiple zonal isolations have become a common completion technique in the oil and gas industry. Sand problems, damaged zones, and water or gas coning are the main reasons for using isolators to sustain or improve oil and gas recovery. However, they have certain effects on pressure behavior of horizontal wells.
This paper introduces new analytical models for studying the effect of this completion technique on pressure behavior of wells with multiple isolated zones. These models have been derived based on the assumption that reservoirs can be divided into multi-subsequent segments of producing and non-producing intervals. Based on the pressure and pressure derivative, the models can be used to estimate the impact of isolators on the pressure behavior. The effects of the number and length of isolators have been investigated for wells having different lengths.
A set of type-curves of dimensionless pressure and pressure derivative versus dimensionless time have been generated for two cases. The first case is for wells in an infinite reservoir having one, two or three isolated zones with three different lengths for the horizontal section and six different lengths for the isolators while the second one is for very long wells in an infinite reservoir. These plots can be used for the type curve matching technique to estimate the number, length, and damaged zones location, segments where sand is produced, and intervals of water or gas coning.
The main finding is that the pressure of these wells behaves similarly for all cases. The dominant effect of the isolators can only be noticed during the early time flow regimes, i.e. during the early radial or early linear. The behavior of the late time flow regimes, i.e. pseudo radial or late linear due to the boundary effects is not affected by the presence of isolators.
Ultra Deepwater Subsalt Reservoir Characterisation: An Integrated Multi-Scenario Approach for Development Planning
Authors: Pippi Olivier , Mayall Mike , Chandler Mike , Dodd Tim , Reid Paul , Taylor Paul 
Published: September 2011

Abstract
Subsea developments of clustered deepwater subsalt fields are challenging both technically and economically. Given the high cost of appraisal wells, the industry tends to rely heavily on seismic technology, pushing the limits in imaging and characterising reservoir through seismic attributes. However, appraisal through seismic in subsalt settings is still uncertain. A fully integrated approach with all available data should be followed to fully describe the uncertainty in order to make an optimised business decision. The objectives of this work are to demonstrate how a systematic methodology was successfully applied to integrate information available from a limited data set, to i) validate the description of the field, and ii) perform a full risk and uncertainty analysis in support of the field development strategy.
This study enabled the building of a solid and integrated description of the field that honours all the sources of data available: seismic, geochemistry, pressures, Drill Stem Test and petrophysics. Analyses from all these data were incorporated into fully flexible static and dynamic models, able to accommodate the entire range of possible geological interpretations, to carry out a rigorous and exhaustive risk and uncertainty analysis.
This work has enhanced the understanding of the subsalt structure complexity and explores the wide range of uncertainty of the reservoirs, resulting in defining an optimised base case development. Alternative scenarios incorporating all the uncertainties identified were generated to quantify their impact and the uncertainty range of the expected outcome in a multi-scenario approach. The thorough risk and uncertainty assessment allowed the identification of the minimum well count to produce the defined resources.
This study offers a sound methodology that proved applicable to characterise a complex field and benchmark its performance against other discoveries. The approach applied is particularly valuable under accelerated development schedules and where seismic characterisation is limited in the description of compartmentalisation.
Application of Hydrajetting Technology Achieves Significant Productivity Increase in Saudi Arabian Gas Producers
Authors: Alabbad E. A. , Solares J. R. 
Published: September 2011

Abstract
Stimulating gas reservoirs, particularly in horizontal producers, has presented a considerable challenge to Saudi Aramco as wellbore accessibility is difficult in wells drilled in deeper formations, with relatively low permeability and high pressure and temperature. Therefore, conventional perforating and stimulation methods have not been as successful as expected when applied in single and dual-lateral completions. Alternative techniques, based on hydrajetting technology, have been recently applied in a number of underperforming horizontal gas producers with excellent results. The technology is used to create slots along the horizontal section and then perform pinpoint acid stimulation treatments. The acid is displaced in the zones in most need of stimulation, resulting in significant well productivity and economic enhancement. This paper provides information about the hydrajetting technology used, and shares details about the successful results and benefits achieved in a cross-section of the significant number of gas producers in which the technology has been applied with an equally positive outcome.
Successful Control of Water Production in Slimhole Completions in a Tight-Gas Sandstone: South Texas Case Study
Authors: Rodriquez Robert , Hall Ryan , Pawlik C.M. (Mike) , Ciezobka Jordan 
Published: September 2011

In deep, south Texas fields, water production is an issue that continues to hinder mature fields and significantly impact operating costs and production performance. These wells are slimhole monobore completions with 2 7/8- or 3 1/2-in. tubing cemented in place. This small restricted inside diameter (ID) limited the available methods of shutting off water in slimhole monobore commingled wells.
In the past, the operator would perforate, fracture treat, and flow test each zone separately. Because of this completion practice (long cycle times) along with a shortage of personnel, equipment, and the cost of materials and services, the company has changed its completion strategy. In an attempt to reduce cycle time and cost, a new, more-effective completion strategy was developed, in which the operating company adopted a continuous operation plan to complete all zones (perforate and fracture treat) of interest and then commingle the production on completion of the fracture treatments in the well. Although this next-generation completion strategy or technique was more efficient, it required additional diagnostics to determine which zones were producing water and if the water-to-gas ratio was hindering the well’s performance.
An organically crosslinked polymer (OCP) was successfully placed into the wells, eliminating or greatly reducing excess water production. Although the reservoir parameters were not in the high-pressure/high-temperature (HP/HT) range, the water shutoff required particular attention. Using this technology, the operator reduced water production and disposal costs and increased gas production in some instances.
This paper presents guidelines for completing successful water shutoff based on case histories from the operator’s field. It describes diagnostic methods used, aspects of the required design criteria, operational concerns, and required quality assurance/quality control (QA/QC) testing. Pre and post-treatment water results are also presented.
Managed Pressure Drilling Enables Drilling Beyond the Conventional Limit on HP/HT Deepwater Wells in the Mediterranean Sea
Authors: Hannegan D.. , Kernche F.. , Pena C.. , Arnone M.. 
Published: September 2011

Abstract
This paper describes some successful applications of Managed Pressure Drilling on deep exploration wells drilled in the Mediterranean Sea. Building upon successful experience utilizing MPD from HPHT jack-up wells, the Operators transferred the experience across to deepwater exploration projects. This represented the first known use of MPD on a floating rig with water depths up to 1,100 m, HPHT environmentand wells drilled to over 6000 m and BHP of up to17,000 psi.
Extensive engineering, training and development of procedures were carried out prior to spud. MPD was utilized to drill up to drill four hole sections in the same well. Specific techniques were developed to handle floating drilling operations. The resulting benefits associated with MPD led to improvements in drilling performance, and eliminated many of the traditional problems faced on other HPHT wells in the area. MPD has now become an integral part of the well operating philosophy and has established new standards for drilling wells of this type in the area.
Some critical wells were classified as wildcats with considerable pore pressure unknowns, coupled with narrow pore-fracture drilling window characteristic of HPHT conditions. MPD was able to minimize the problems faced on the wells by enabling various techniques to be utilized. These techniques included the use of pressure build up analysis to quantify formation pressures, the application of dynamic flow checks, dynamic formation strength limits, and the application of constant bottom hole pressure during dynamic and static drilling fluid circulation conditions. The planning, development and execution phases of the MPD projects are detailed in this technical paper.
Transient Pressure Analysis of Horizontal Wells in a Multi-Boundary System
Authors: Al Rbeawi S. , Tiab D. 
Published: September 2011

Abstract
Horizontal wells can greatly increase the contact area of the wellbore and the pay zone; so they are commonly applied in oil reservoirs to enhance the production and ultimate recovery, especially in low permeability formations.
The purpose of this study is to develop a technique for the interpretation of transient pressure based on dimensionless pressure and pressure derivative. Type curve matching is one of the techniques that can be used to interpret the pressure data of horizontal wells in finite reservoirs. Starting from very short horizontal wells to extra-long wells, the pressure behavior of the wells has been analyzed for different conditions. The effect of the outer boundaries of the reservoir on the pressure behavior of the horizontal wells has been investigated for different configurations. Rectangular shape reservoirs with different dimensions have been used to study the pressure response in the well.
Five flow regimes have been observed for regular length horizontal wells; early radial, early linear flow, pseudo radial flow, channel flow or late linear flow, and pseudo-steady state flow. While only four flow regimes have been observed for the extra-long wells; linear flow, pseudo radial flow, channel flow, and pseudo-steady state or boundary affected flow. Of course, those flow regimes do not always take place under all conditions. Pseudo-steady state flow is expected to occur after long producing time. A pressure drawdown test was solved using the proposed type curve matching technique.
The study has shown that the effect of the boundary on the pressure response of the horizontal wells and the type of flow regimes depend on the length of the horizontal wells and the distance to the nearest boundary.
A Pilot Test of Continuous Bottom Hole Pressure Monitoring for Production Optimization of Coalbed Methane in the Raton Basin
Authors: Rotramel Jennifer , Bell Morris 
Published: September 2011

Abstract
Pioneer Natural Resources (Pioneer) operates over 2200 Coalbed Methane (CBM) wells in the Raton Basin in Colorado. The wells produce out of two formations: the upper Raton and the lower Vermejo Formations. Many of the wells in the basin are completed in only one formation, with two wells on each pad; each well is completed in one of the formations. A number of the wells in the basin are completed in both formations and have commingled production. Pressure drawdown is critical in coalbed methane production, particularly in wells with large commingled perforation intervals; this is accomplished by lowering the gathering pressures and lowering the annular producing gas-water interface (fluid level) of the wells down below the perforation intervals. Pioneer uses acoustic measurement tools to determine the fluid level in the majority of the wells. However, in some of the wells, particularly the commingled wells, the acoustic tool is unable to measure the fluid level.
A different method to determine the fluid level is to measure the bottom hole pressure and calculate the fluid level using a downhole pressure gauge. To test pressure gauges in the Raton basin, three wells with large perforation intervals were chosen for a pilot test. Pioneer also chose three companies with different components for comparison. The system was designed to be durable and mobile; it was also designed to connect to the existing production monitoring system. The installations for the three wells were successful, though, there were two gauge failures and several pump failures. After the failures were analyzed, and the production of the wells had stabilized with the fluid below the perforations, two of the gauges were moved to other wells. The intermittent acoustic measurements were compared with the pressure gauge information and the two tracked closely; this increased the confidence in the acoustic measurements when values can be obtained. Several of the goals of the pilot project were achieved, including developing the successful system as planned and obtaining reliable bottom hole pressures. There were additional unexpected results from the project; the failure analysis of the pumps lead to a solution for pump problems in the field, and the results provided Pioneer with a visual training tool for the field employees. It is too early to determine if the gauges could be used to more efficiently manage the commingled wells in the field, but a larger dataset of wells may improve the understanding.
Merging Coiled Tubing and Swellable Packer Technologies
Authors: Brooks R. T. 
Published: September 2011

Abstract
For a number of years one of the main areas being developed has been multilateral wells to better access the reservoir. One of the greatest challenges in operating an efficient multilateral well is having control of where any water production is coming from. Effectively managing produced water can bring obvious benefits to the economics of a well. One tool that has not been exploited for this type of application is swellable packers. Coiled Tubing and Swellable Packer technologies were recently combined on a land-based operation in Holland to successfully isolate a water-producing leg of a well lateral. The operator asked for a proposed completion solution after a previous attempt to isolate the lateral had proved unsuccessful.
The proposed solution was designed to straddle the lateral entry/exit with a scab liner, isolated and anchored at either end by water-swellable packers. The straddle was required to seal inside the main bore casing and withstand a differential pressure at well operating temperatures. Swellable packers were selected from the various proven openhole isolation devices available to the industry to provide the zonal isolation required in the multi-zone intervals. This was the first swellable straddle completion in Holland in a watered out, commingled gas environment in which isolation would be contained solely by swellable packers.
The water producing lateral was successfully straddled using two water swellable packers run with base pipe between the two packers. In this application the Swellable Straddle was deployed in conjunction with an additional mechanical packer to anchor the straddle whilst the swelling process in the aqueous environment took place. A subsequent intervention with coiled tubing and a resettable Inflatable Test Packer confirmed the straddle had successfully sealed and had isolated the water producing lateral.
This paper presents a solution to the challenges of isolating laterals using swellable packers and coiled tubing, and how to verify that the junction has been successfully isolated.
World's First Production Logging with Fiber-Optic-Enabled Coiled Tubing (CT)
Authors: Noya V. , Adil A. R. , Wolf K. , Chee S. S. , Stuker J. , Rodriguez F. 
Published: September 2011

Abstract
The coiled tubing (CT) e-line system is ideal to perform real time production logging (PL) in long horizontal wells, however, the wireline cable inside the CT can restrict the pump rate while the large volumes of acid normally pumped could potentially damage the CT pipe's integrity. Furthermore, using two different CT strings, one for pumping acid and another for performing the PL in real time is neither practical nor economical. A common approach is to use a memory PL tool (PLT), with the associated drawback of recording poor quality data or eventual misruns.
To overcome these challenges, a new CT multipurpose system has been developed, allowing real time PL and conventional applications. Leveraging on the telemetry offered by the fiber optic enabled CT (FOECT), already used for downhole measurements while treating in the M field; the new downhole assembly enables the use of standard PLTs in real time mode. At the surface, the converted optical signal is transmitted wirelessly to the PL engineer's portable computer; eliminating the need for conventional acquisition equipment and personnel.
In a world first application, the system was used in a land water injection well, after the stimulation job; obtaining the injection profile log with the same quality measurements as a conventional wireline conveyed log. Moreover, the data demonstrated a uniform injection profile. Additional field applications are also briefly discussed in this paper.
The new multipurpose FOECT reduces the mobilization and logistics otherwise required, as well as the time and cost compared to existing alternatives. This new capability can be extended to other scenarios like offshore or remote environments, where operational costs have a larger impact. Ultimately, the system opens the door for performing diagnosis, treatment and evaluation in a single well intervention mobilization; making CT operations more efficient and providing more data for production engineers.