bluuebunny/crossref_metadata_2025_split huggingface dataset:
Metrics for Evaluating Cementing Success
Authors: Duckworth Deborah 
Published: April 2009

Abstract
Many papers and books have been written relating the importance of cementing operations to the success of drilling and completions operations. While cementing costs typically represent less than 10% of total planned wells costs for domestic US onshore operations1, the failure to get good zonal isolation and adequate cement bonding to the casing and formation can be catastrophic…from loss of potential pay zones to the loss of the entire well. Even operator personnel involved with cementing on a regular basis may take the operation for granted. "Cementing should be seamless." "It is not a commodity that I am as tied into as mud or casing."2 Often the success of the cementing operations is measured on location with a single drilling report entry…Bumped the plug and floats held. Good cement job. But was it really a good cement job? Does bumping the plug and pumping all the cement really reflect the efficiency and quality of the job? A recent two year cementing project in Wyoming provided both the operator and the service company an opportunity to develop metrics for evaluating cementing success that go beyond "bumping the plug". The purpose of this paper is to present the key performance indicators developed and demonstrate how to apply them to other cementing projects to quantify cementing success. For the seasoned engineer this paper provides a review of the importance of cementing operations while newer engineers may use it to become more familiar with the scope of planning and implementing successful cementing operations.
Multiphase Meter Production Well Testing Applied to Low-GOR Mature Fields
Authors: Mehdizadeh Parviz , Farchy David , Suarez Jairo 
Published: April 2009

Abstract
In many mature fields production well testing is limited by the availability of test separator. Prior industry attempts to utilize the new technology of multiphase metering to fill this gap has been hampered by the cost of multiphase meters. This paper describes the development and field tests of a low cost portable multiphase meter. The meter utilizes the Coriolis flow meter technology combined with a microwave based water cut meter that can measure WC in the 0-100% range. The combination of these techniques provides a light weight metering package that can be mounted on trailer for portable well testing. This multiphase meter can measure oil, water and gas without separation of the production stream at low GOR. These applications can be found in mature fields with low GOR and in heavy oil fields.
The multiphase meter was subjected to field qualification tests prior to deployment in a West Texas field. The paper describes the results from the qualification tests and the performance history during the 18 months of deployment in the field. Well test data from the multiphase meter is compared to conventional test separator and grab samples. Comparison between the test separator and the multiphase meter shows average liquid flow deviation of about ±7%. The water cut was measured within 1-2 points of the water cut from the test separator.
A Case Study Examining a Cost-Effective Gel System for Water Shutoff in a Low Pressure Layer
Authors: Major C. R. , Hines D. N. , Gould J. H. , Pender D. B. 
Published: April 2009

Abstract
An innovative system consisting of three different Chromium Carboxylate Acrylamide Polymer (CCAP) gels is being used in place of conventional cement squeezes in the Upper Spraberry formation located in West Texas. The application of the CCAP gel to shut off water production by abandoning the Upper Spraberry formation has resulted in increased oil production, lower workover costs and reduced lease operating expense (LOE) in the majority of the wells that have been treated to date.
A typical Spraberry Trend Area well consists of the Upper and Lower Spraberry and Dean formations. After fracture stimulation, the intervals are produced by beam pump. Reservoir characteristics and the completion configuration cause the Upper Spraberry formation to be more susceptible to water encroachment. Because the Upper Spraberry has low reservoir pressure, conventional squeeze cementing is difficult. The hydrostatic pressure resulting from a column of cement will further breakdown the formation requiring high cement volumes and/or multiple squeeze attempts in order to successfully shut off the interval. As an alternative to conventional cement squeezes, gel treatments with volumes between 700 and 1,000 barrels using three different gel systems are used to successfully shut off the Upper Spraberry formation.
One hundred eight wells have been treated to date. Many of the wells initially treated in 2003 are still benefiting from the gel treatment, maintaining oil production with lower water/oil ratios. Gel treatments have been successful in increasing or restoring oil production, and reducing operating expense and workover cost. Increases in gel treatment cost have been minimal over the years compared to that of cement. The gel treatments have proven to be a cost-effective, long-term alternative for conventional cement squeezes.
Determining the Optimal Artificial Lift Strategy When Operating a Mature CO2 Flood in the Real World
Authors: McWilliams Jay Paul , Gonzales David 
Published: April 2009

Abstract
Effectively operating artificial lift systems can be a very challenging endeavor when implementing tertiary recovery on a mature oil field. The desire to produce a maximum amount of oil must be balanced with the physical limitations of the artificial lift equipment. The traditional operating limitations of artificial lift equipment may be too liberal in a CO2 flood. Being too aggressive when attempting to reduce fluid levels can lead to excess failures and thus, reduced overall production and excessive costs.
Attempting to determine the optimal artificial lift strategy in this environment can be a daunting task. Traditional models for determining operational policy may not capture all of the dynamics that affect the performance of the system. An empirical approach can be helpful in setting artificial lift guidelines.
This paper discusses the results of an empirical analysis of an artificial lift system's performance in a mature CO2 flood vs. the performance in a mature water flood. For the analysis, data from two oil fields in southeastern Utah, the McElmo Creek Unit (mature CO2 flood) and the Ratherford Unit (mature water flood) was compared and contrasted. The data was analyzed using statistical modeling tools to determine the appropriate strategy for the system. The results from the review gave significant insights to the optimal strategy for operating the system and will be discussed.
Green Proppant Systems From Locally Available, Low-Cost Materials
Authors: Santra Ashok , Saini Rajesh , Luo Hongyu , Norman Lewis , Parker Mark 
Published: April 2009

Abstract

Description of Materials
Recycled materials and waste products, such as glassy materials, igneous-rock tailings, and Portland cement-based materials, have been used to prepare new proppants. Both conventional recycled glass, such as plate glass, e-glass, and common bottle glass, have been explored in addition to unconventional sources, such as materials generated from the burning of sewage sludge. Undersized materials, such as fines from the processing of the minerals to make roofing-shingle granules, have been used to prepare proppants. Recycled concrete may also be used to manufacture proppants.

Applications
All of the above mentioned proppants are useful in place of conventional sand and intermediate-strength proppants in applications including gravel packing and hydraulic fracturing.

Results
Glass-based proppants are known for their catastrophic failure and tendency to crush into fine particulates. New processing methods allow for mitigation of this shortcoming by generating proppants that closely resemble the performance of conventional sand proppants. Igneous materials can be processed to create proppants that exceed the performance of sand proppants and approach that of conventional intermediate-strength ceramic proppants. Portland cement-based proppants have been developed with a SG as low as 1.6. New processing techniques allow for lower sintering temperature compared to commercial ceramic proppants, resulting in reduced energy consumption during manufacture. Recycled concrete has been used to generate proppants that resemble conventional ceramic proppants but are also processed at reduced temperature to reduce the energy required during manufacture. API testing, such as crush and conductivity tests, are reviewed in this paper for comparison to conventional proppants. These new proppant systems are desirable because of a potential lower cost and for their sustainability during manufacture. In some aspects of performance, the new proppants exceed conventional proppants.

Significant New Contribution
Several new materials systems are presented for consideration in the manufacturing of proppants. In some cases, these systems make use of recycled materials or waste materials and, in other cases, these systems are processed at reduced temperature to reduce the energy required during manufacture, compared to conventional proppants. As potential opportunities for new proppants, these materials are presented to the oilfield community to judge whether they are technically and commercially viable.
Well-Performance Diagnostics Using Smart Plunger Technology
Authors: Gray Travis P. 
Published: April 2009

Abstract
Plunger lift system installations throughout the United States are experiencing an alarming boom as liquid loading becomes an ever-increasing impediment to hydrocarbon recovery in depleting wells.
Newly installed plunger lift installations within a field normally required individual onsite calibration at each well site. Accurate calibration of these installations can take many hours or even days to ensure optimal capability to recover liquid within the tubing string at acceptable rates. Operating expenses in turn often increase reflecting the time needed on location to "tune" the system to levels approaching maximum operational efficiency under plunger lift. Given the increase in the number plunger lift installations within a field(s) and resulting limitations in onsite operator calibration time at each installation, the need for automation to aid in "efficient tuning" of each individual plunger lift installation is critical to maintaining a steady production decline in a well with liquid loading characteristics.
Today, with the advent of modern automation technology, it is possible to access and manage all plunger lift installations within a producing field remotely. This can be accomplished with the aid of a personal computer connected to the field's collective network of plunger lift controllers via the use of a SCADA (Supervisory Control and Data Acquisition) system supported by key control system components such as Programmable Logic Controllers ("PLC") and Remote Terminal Units ("RTU"). These provide a field operator with the capability to perform basic operational tasks (e.g. the closing and opening of valves), without being present at the well site and allow for the plunger lift installation to adapt to changing field conditions without operator interface.
This paper will address the proper application of Smart Plunger Diagnostic Technology in the field with the objective of increasing plunger lift installation efficiency in turn leading to improved well productivity with minimal increased operating expense.
New Sucker-Rod Connection Designed for High-Load Applications
Authors: Telli Francisco Diaz , Muse Daniel , Fernandez Ezequiel , Pereyra Matías 
Published: April 2009

Abstract
The present paper describes the premium connection (PC) sucker rods field experience in various applications and shows the results collected until now. Ay the moment this paper was written, 11 wells were working with this sucker rods under different loads ratings.
A New Nodal Analysis Technique Helps Improve Well Completion and Economic Performance of Matured Oil Fields
Authors: Awal M. Rafiqul , Heinze Lloyd R. 
Published: April 2009

Abstract
Mature fields lack the sparkle of a new play, and an operator typically will not invest capital for waterflooding, much less EOR. But prevailing higher oil prices can turn such a mature oil field more profitable by employing innovative production enhancement techniques. We propose the use of a simple, tapered tubing string completion (using larger internal diameter (ID) tubing pipes in the upper sections) that can be customized for specific reservoirs. Historically there are few instances of tapered ID tubing completion, which were basically necessitated by technical constraints (liner, workover, etc.). But our approach is focused on enhancing economic performance. We have employed nodal analysis technique to develop an equivalent tubing diameter (ETD) concept. The ETD allows for comparing the well performance for single-ID tubing completion. The procedure also seeks an optimum length for the larger tubing ID in the upper section. Using reservoir simulation for full life cycle, and oil prices projected over time until abandonment, the economic performance is evaluated using NPV and other economic parameters.
The proposed production enhancement method is suitable for wells with moderate to high open flow potentials (AOFP). It is especially suited for low GOR wells with high future water-cut that will eventually require an ESP system, and also remote oilfields, where reservoir pressure maintenance and EOR is not viable.
The use of larger tubing ID section entails only a marginal increase in CAPEX. However, the tapered completion gives increased production rate sustained over a long time, which results in significant economic gain. The economic benefits accrue from the prevailing high oil price, yielding a quick payout and many returns on investment.
The proposed completion approach does not involve complexity, and the innovative application of nodal analysis coupled with high oil prices show how to make mature oil fields onshore and offshore, more profitable.
Modified Foss and Gaul Model Accurately Predicts Plunger Rise Velocity
Authors: Rowlan O. Lynn , Lea James F. , McCoy J. N. 
Published: April 2009

Abstract
Accurate prediction of the average plunger rise velocity is important to optimally unload liquid from a plunger lifted well. A modified Foss and Gaul model presented in this paper predicts the minimum build casing pressure criteria to open the motor controlled valve for a selected plunger rise velocity. Results from the modified Foss and Gaul model are contrasted with results from the original Foss and Gaul model. The minimum build casing pressures predicted using both models are compared to measured casing pressures at the same rise velocities measured from field data acquired on 10 different plunger lifted wells.
During the shut-in time period the plunger falls through gas, liquid and then rests at bottom on the bumper spring. At the end of this time period when the surface valve opens sufficient pressure is required to build to enough magnitude to unload the accumulated liquid and conventional plunger from the bottom of the well to the surface. An industry rule-of-thumb load factor criterion is frequently used to determine at what casing pressure build, Pc, the well should be opened to unload the liquid to the surface. The best technique to predict the maximum casing build pressure, Pcmax, is to use a Foss and Gaul type model to predict the rise velocity within a range of 500-1000 feet per minute (fpm), more optimally at 750 fpm that will unload the plunger and liquid to the surface.
The modified Foss and Gaul model favorably predicts a required casing operating pressure to bring the plunger and liquid to the surface at a specified average rise velocity. Using the modified model will allow an operator to determine the maximum shut-in casing pressure a plunger lifted well should be allowed to build before opening the valve and safely bring the plunger to the surface.
Quickly Identifying Well Problem by Modern Production Analysis for a Better Stimulation Plan
Authors: Wang Sharon , Túnjar César 
Published: April 2009

Abstract
Diagnosing well performance problems before stimulation treatment is an important step to successfully improve a well's productivity. Normally, the method used to do this is well testing. Unfortunately, often no well testing is done in a well before planning a stimulation treatment. An operation engineer then has to determine the causes of a well underperformance without well testing data. This is one challenge an operation engineer has to face before he/she designs a stimulation job. Another common challenge is inadequate data available to analyze a well's performance. In many instances, the only data available to an operation engineer is the production data. The critical questions then are how to get the insight of a well's production problem, and how to evaluate well performance and reservoir potential by the limited data. These are real challenges for engineers attempting to develop an effective stimulation design. The modern production analysis derived from pressure transient in well test is a practical and economical alternative to well testing for evaluating well performance, and the needs of a treatment.
This paper presents an effective method of how to quickly identify well problems with a limited amount data. Two case studies have been conducted in how to assist an operation engineer in development of a proper stimulation plan.
Acoustic Liquid Level Testing of Gas Wells
Authors: McCoy J. N. , Rowlan O. Lynn , Podio A. L. 
Published: April 2009

Abstract
Initially Gas Wells usually flow at sufficiently high rates to remove all liquids from the wellbore. When the gas flow rate decreases below critical rate1 some intervention such as compression, surfactants, and/or velocity strings is required. At a later time when either reservoir pressure and/or gas flow rate is sufficiently reduced, then other means of artificial lift (usually such as plunger lift, gas lift, or sucker rod lift) must be added to maintain production. Acoustic fluid level testing can be used to investigate the producing condition of a gas wells. Developments in digital acoustic fluid level technology have resulted in the operator being able to undertake fluid level measurements and use this technology to investigate the status of his gas wells. The act of acquiring a fluid level on a gas well is an inexpensive and non-intrusive process. Examples of acoustic tests are presented, where the test are performed on shut-in or flowing above or below critical flow rate gas wells with or without surfactant treatments acquired down the tubing or the tubing/casing annulus.
Techniques for acoustic liquid level analysis are discussed for gas wells where unusual conditions exist such as very shallow liquid levels, very deep liquid levels, noisy wells, high bottomhole temperature, and low or high surface pressures. Some gas wells have gas lift mandrels, liners, multiple zones of perforations, tubing holes, flush pipe and other conditions which result in the acquisition of difficult to interpret acoustic traces. This paper describes analysis techniques used to determine the distance to the liquid level in gas wells with these unusual conditions. The analysis is based on data obtained at the surface without entering the wellbore and yields accurate representation of the conditions existing on the surface, within the wellbore and within the reservoir.
Experimental Study on Fiber Sweeps in Horizontal and Highly Deviated Configurations
Authors: Ahmed R. M. , Takach N. E. , Savitri M. 
Published: April 2009

AbstractCuttings transport in horizontal and highly deviated wellbores is challenging because the fluid velocity in these wells has a reduced vertical component. Hole cleaning sweeps are applied to reduce cuttings accumulation in the wellbore. Field studies indicate that fiber-containing sweep fluids have been very effective in cleaning horizontal and highly deviated wells. Although the results of preliminary field studies are encouraging, very little is currently known about cuttings transport efficiency of fiber sweeps.This article presents results of experimental investigations conducted to study hole cleaning performance of fiber sweeps. Flow loop experiments were performed in horizontal and inclined configurations using two test fluids: i) base fluid (0.47% Xanthan Gum); and ii) fiber sweep (0.47% Xanthan Gum with 0.04% synthetic fiber). Rheological properties of the test fluids were very similar. Experiments were conducted by eroding cuttings deposited in the test section at a constant flow rate and measuring the amount of cuttings removed by the base and sweep fluids. Results indicate that the fiber sweep has better hole cleaning capabilities than the base fluid in the horizontal configuration. When tests were conducted in an inclined configuration (68° from vertical), improvement in the hole cleaning capability of the fluid due to the addition of fiber is moderate. The experimental results and findings of this research are very useful for directional and extended-reach well drilling applications.
Novel Completion for Effective Deliquification of Natural Gas Wells
Authors: Wang John Yilin 
Published: April 2009

Abstract
Liquid loading has been a problem for natural gas wells for several decades. With gas fields becoming mature and gas production rates dropping below the critical rate, deliquification becomes more and more critical for continuous productivity and profitability of gas wells.
Current methods for solving liquid loading in the wellbore include plunger lift, velocity string, surfactant, foam, well cycling, pumps, compression, swabbing and gas lift. All these methods need to lift the liquid up to surface, which increases the operating cost, onshore and offshore. A better completion method has been developed to separate and reinject the liquid into the reservoir formation.
The new completion method – wellbore separation and reinjection through vertical well or horizontal well – depends on reservoir permeability, reservoir pressure, formation thickness, liquid production rate and geology. Through numerical reservoir simulation study, these parameters have been quantified and optimal completion has been developed for particular reservoirs based on gas recovery. Effect of liquid loading on gas productivity has also been investigated in two aspects: backup pressure and near-wellbore-liquid blocking. The new completion methods can increase gas recovery, prevent scale problem in the wellbore and surface pipeline, and avoid the liquid lifting and processing. It is an effective, economical, and environment friendly technology for natural gas wells.