bluuebunny/crossref_metadata_2025_split huggingface dataset:
Completion Optimization in the Lower Huron Shale in Kentucky
Authors: Wozniak Gregory , Vactor R. Taylor , Hina Derek 
Published: February 2011

Abstract
EQT Production has been an active driller in the Lower Huron Shale in the Appalachian basin for nearly 100 years and has close to 5000 producing vertical wells in Kentucky alone. In 2006, EQT began drilling horizontal wells and has drilled over 400 Lower Huron Shale and over 100 Cleveland Shale wells in Kentucky through mid-2010. EQT has experimented with various completion designs and fracture methods in order to maximize production from these wells. EQT traditionally has performed both foamed nitrogen and nitrogen gas hydraulic fracture treatments, with the selection between the two dependent on reservoir pressure data taken from vertical offset wells drilled and completed in past decades. EQT also performed 33 hybrid (ultra-high quality foam) treatments on Lower Huron wells and compared their production against the production from their offsets. EQT studied the effect that frac stage length has on well production. The method in which the open-hole packers were set was also analyzed and found to be influential in well performance. From these studies, EQT has identified ways to improve well performance for a minimal cost by altering the completion design and has implemented these design changes in their completion programs.
Integrated Discipline Approach to Conquer Asphaltene Challenges in On-Shore Abu Dhabi Oil Fields
Authors: Grutters Mark , Ramanathan Karthik , Naafs Dennis , Clarke Ed , Huo Zhongxin , Abdallah Dalia , Zwolle Simon , Stankiewicz Artur 
Published: February 2011

Abstract
This paper describes an integrated discipline approach to investigate and mitigate asphaltene challenges in an onshore Abu Dhabi oil field. This large carbonate field produces from three reservoirs with substantial lateral variation of fluid properties. Several wells in the northeastern part of the field producing from one of the three oil reservoirs suffer from asphaltene deposition in the wellbore. A multidisciplinary team of experts from Shell and ADCO worked closely together to evaluate the natural controls on asphaltene stability in this oilfield and to predict whether deposition in other areas of the field may be expected in the future. In addition, a robust inhibition and mitigation strategy has been developed.
A thorough review of production and well intervention data, combined with detailed analysis of field deposits confirmed that wellbore deposition was due to asphaltenes in approximately one third of all the affected wells. In order to understand the variability in fluid properties, a wellhead sampling and fluid analysis campaign was carried out (39 wells distributed across the field). Analyses of basic fluid properties such as API, S%, Ni, V, SARA supported by more sophisticated geochemical characterization data of the reservoir fluids clearly demonstrated that the lateral variability in fluid properties from NE to SW is attributed to two processes: (1) geological mixing of fluids from different sources into the reservoir, and (2) maturity variation of fluids form the same source in the reservoir. Furthermore, stock tank oil asphaltene stability tests clearly indicated that fluids from the NE have a high tendency to be unstable with respect to asphaltene precipitation, and fluids from the SW of the field are stable. These results are in agreement with field observations. The confirmation of the field data with simple laboratory tests allowed for the development of empirical correlations between certain fluids properties and the risk of asphaltene precipitation and deposition. Based on this it was concluded that deposition is not expected to expand to the SW part of the field during the production lifespan. Moreover, a cluster of wells has been identified in the NE were deposition has not occurred to date but with a high propensity for deposition if production conditions will change. For these wells and the ones with confirmed asphaltene deposition problems additional live-oil testing, thermodynamic modeling as well as a surveillance plan have been suggested, which will further improve the correlations and help to identify challenges ahead of actual deposition.
Field/Well Integrity Issues, Well Abandonment Planning and Workover Operations on an Inadequately Abandoned Well: Peace River Alberta Case Study
Authors: Diller Chris 
Published: February 2011

Abstract
Maintaining well integrity for field lifecycle operations is a major factor that must be taken into account in the planning and execution of all Well Engineering activities. Some legacy wells are not properly abandoned to prevent the contamination of secondary reservoirs and/or groundwater from other producing hydrocarbons, or from emerging carbon capture and acid gas storage projects being planned by both oil and gas operators and government research groups. If these wells are not identified and properly abandoned, there is a high risk of negative impact to the environment, operator reputation, and the economics of field operations.
This case study will examine the complex re-entry and re-abandonment of a well in the Peace River Alberta region of Alberta, Canada. In the process of developing the plan to re-enter and abandon this well, a methadology for abandonment planning was adopted with three essential attributes: the abandonment should provide effective isolation of all critical zones, operations should allow for evaluation and confirmation of zonal isolation, and the final condition of the well should allow for a simple re-entry to remediate future isolation problems. Throughout the planning and execution of the program, the regulating agency was integrated into the decision-making process. To complete the abandonment, technologies such as casing drilling, downhole cameras, and magnetic ranging were employed along with directional drilling, coiled tubing, and fishing operations. Upon completion, the effectively executed abandonment program met or exceeded prescribed technical and regulatory requirements. The positive results of performing this operation included mitigating environmental impacts, delaying the capital-intensive construction of a future sour gas treatment plant, and allowing the extended operation of the Peace River Complex.
Pushing the Limits for Field Development
Authors: Hoch E. , Ohrt H. B. , Brink D. I. , Flikkema J. , Noman R. 
Published: February 2011

Abstract
The giant Al Shaheen field, offshore Qatar includes a stacked sequence of Lower Crectaceous, carbonate domimated reservoirs of a tight nature and limited thickness. A holistic development approach with real time adaption has been used to push the boundaries for the development and the field is today producing more than 300,000 barrels of oil per day in an injection supported development including the world’s longest horizontal wells of up to 12 kilometres. Innovative completion solutions, providing the means to manage reservoir heterogeneity further supports the adaptive development and have opened new possibilities for enhanced oil recovery.
After discovery in the mid 1970’s the breakthrough in the development came in 1992 when Maersk Oil introduced horizontal well technology from the North Sea tight chalk fields. Effective drainage by the horizontal wells via increased reservoir contact in the thin and tight pay zones has been confirmed from pressure measurements, saturation profiles and seismic data. The horizontal wells have further allowed the 700 sq km offshore development to be developed from 9 platform locations. Development of the tight and thin reservoirs in the Al Shaheen field is challenged by lateral heterogeneities, dipping fluid contacts and varying oil viscosities. The ability to handle heterogeneity is supported through innovative horizontal completion solutions ranging. The development is based on high resoluition 3D reservoir models and development adaption to real time static and dynamic field information.
Obtaining the optimal oil recovery is based on a detailed development strategy tailor made to specific reservoir characteristics and reservoir management and injection and production control.
Hydrophobic Filming Reduces Frac Gel and Mineral Scale Damage
Authors: Weaver Jim , Nguyen Philip 
Published: February 2011

Abstract
Coating proppant with a surface modification agent (SMA) provides cohesion between grains, resulting in the formation of proppant aggregates. This adhesion has been proven throughout many years of use to provide a variety of benefits, including increasing pack porosity and permeability by hindering compaction, reducing proppant flowback, controlling fines invasion into the proppant pack, and minimizing the migration of fines within the pack. A general review of the contributions to improved and sustained fracture conductivity is provided.
There are two additional, important properties of SMA treatments that have not been previously described in detail. The first of these regards the reduction of gel damage expected with the use of guar-based fracturing fluids. Even when highly effective gel breakers are used, significant conductivity damage is often observed with typical guar-based frac fluids. Data are presented showing that coating proppant with a hydrophobic film significantly reduces the conductivity damage caused by guar-based fluids. Treatment with SMA results in wells that clean up faster with increased productivity.
The second property recently demonstrated is that mineral scaling in the proppant pack is inhibited by coating the proppant with a hydrophobic film of SMA. The scaling can be rapid, caused by water incompatibility of the fracturing fluid with the formation. Geochemical scaling can occur when aluminum-based proppants are used because of incompatibilities between proppant and formation mineralogy. Scaling in the proppant pack is often noted by steeper-than-expected productivity decline curves, ultimately leading to premature refrac treatments. It has been found that coating the proppant surface and the formation face with a strong, hydrophobic film significantly reduces the tendency for mineral scaling to occur in the fracture and extends the life expectancy of a fracture treatment.
Application of J-Functions to Prepare a Consistent Tight Gas Reservoir Simulation Model: Bossier Field
Authors: Rojas A. 
Published: February 2011

Abstract
For a tight gas field with a pressure depletion drive mechanism like Bossier Field, it is critical to promptly develop an accurate reservoir simulation model that will help the reservoir engineer understand reservoir behavior, estimate well reserves and evaluate infill and acceleration opportunities.
This paper describes a technique that calculates accurate fluid distributions honoring the physics of the rock such as capillary forces, rock texture, permeability and pore volume distributions. Saturations that make physical sense enable the reservoir simulation model to more accurately estimate reserve and production forecasts that yield a higher level of confidence in the economic evaluations and optimum well planning.
The technique uses laboratory capillary pressure curves coupled with permeability-porosity measurements to generate J-Functions. A J-Function is an average data method proposed by Leverett for correlating capillary pressure data. (Leverett, 1941). The average correlation is based on the fact that geometrically similar rocks have capillary pressure with similar behaviors. The J-Function of geometrically similar rocks will overlay for samples that may differ in permeability by an order of magnitude. The Leverett J-Function is a powerful tool to average data from several samples and to look for outliers of different rock types. Once these J-Functions are identified, they are input into the reservoir simulation model for flow simulation and history matching.
Using this technique the transition from model initialization to flow simulation proved very smooth. The historical production was easily matched increasing the confidence in the outlook. Some of the wells were not in boundary dominated flow; the initial forecasts were underestimated because some of the wells were not in boundary dominated. This technique indicated these reservoir volumes would be produced through existing wells. New infill and acceleration opportunities were developed. Down spacing was determined to be uneconomic.
Natural Gas Lift Method for Wellbores With Multiple Open Formations
Authors: Rodriguez A. , Schott R. 
Published: February 2011

Abstract
Inefficient production of wells with multiple open formations to one wellbore is usually caused by liquid loading, liquid blockage between formations, interference, and crossflow. There are numerous ways that have been tried to flow all the formations efficiently but usually, at the end, the techniques used either give more opportunity to one formation (e.g.: new recompletions) and give up on other formation/s production (e.g.: older, more depleted formations, lowest formation in the wellbore). After long study, testing, and analysis of results we have developed the “Natural Gas Lift” method that can effectively produce all zones with a single string of tubing, keep all selected zones isolated, able to use existing artificial lift equipment like plungers/surfactants through the whole string of tubing to assist in deliquification, and at the same time produce all the formations in the wellbore more efficiently and economically.
Lessons Learned Developing the Eagle Ford Shale
Authors: Mullen J. , Lowry J.C. , Nwabuoku K.C. 
Published: February 2011

Abstract
The Eagle Ford shale play located in south Texas is in its infancy in terms of development compared to other shale plays in the USA. The Barnett shale has been commercially productive since the1980s and the Haynesville has been commercially productive since 2005, whereas the Eagle Ford has only been producing since 2009. Thus, there is significant risk involved in drilling a horizontal Eagle Ford well because the reservoir's characteristics change depending on the location, producing gas, gas condensate, and oil. A few operators have successfully made the transition in the last year from vertical to horizontal-wellbore programs in the gas window and there is a need to shorten the learning curve to successfully develop the play. One such method involves the use of wireline logs, such as cased-hole pulsed-neutron logs (PNL), run in the lateral to determine the reservoir characteristics and to aid in tailoring the hydraulic fracture treatment. Following this horizontal well's completion, a review of the mud log, cased-hole PNL, and tracer and production logs in the lateral in conjunction with the stimulation treatment was conducted to determine which zones produced as expected and, more importantly, which zones did not produce as expected. This paper focuses on reviewing all log data pertaining to this well in combination with the completion treatment and production to identify possible relationships between production performance, the reservoir and the completion, and moreover to determine what would be done differently in future wells, in addition to reviewing additional offset well-data.
Shale Gas Plays: A Performance Perspective
Authors: Sutton R.P. , Cox S.A. , Barree R.D. 
Published: February 2011

Abstract
The production of natural gas from shales traces back to the first well drilled in New York in 1821. Over the past 25 years, access to this resource has grown. Recent advancements in drilling and completion technology has enhanced well production rates and production from shales has increased to where it currently supplies 20% of the gas produced by all gas wells in the United States. Well performance data from these shale plays has been compiled and analyzed to develop insight into these tight reservoirs. These results are compared and contrasted to determine similarities and differences among the plays. Comparisons with classical gas reservoirs and tight gas reservoirs are made to provide additional insight.
Removing Iron Sulfide Scale: A Novel Approach
Authors: Yap Juliet , Fuller Michael J. , Schafer Laura A. , Kelkar Shrihari 
Published: February 2011

Abstract
Iron sulfide is a common scale-formation in sour-gas wells that restricts tubular diameter, reducing well productivity. Compared to other scales, iron sulfide has unique risks associated with chemical removal. For example, due to the corrosiveness of hydrochloric acid (the most common chemical agent for both sulfide and carbonate scale removal), damage to the completion metallurgy at elevated temperature limits its applicability. Another main concern related to the use of acid for iron sulfide removal is the rapid generation of H2S byproduct and the risks associated with production of this toxic gas to the surface.
Owing to H2S toxicity and the resultant elevated corrosion risk, new chemical solutions are needed for high-temperature FeS scale dissolution with low H2S generation. This study describes the development and characterization of a powerful noncorrosive solution for iron sulfide removal based on a chelating agent. Testing shows the fluid dissolution capacity under varied temperatures, scale-surface area, treatment fluid volume, and exposure time. Tests are also included showing the comparative benefits in dissolution capacity compared to other commercially used products such as diethylenetriaminepentaacetic acid (DTPA) and Tetrakis (hydroxymethyl) phosphonium sulfate (THPS). Finally, the mild-pH of the new chemical solution provides significantly lower corrosion rate.
This work describes an altogether new family of chemicals for sulfide scale, providing high dissolution capacity, low corrosion rates, and limited generation of toxic H2S.
Gas Injection Pilot Field Case: An Integrated Monitoring Plan to Tackle Pilot Results and Identify Uncertainties in Heterogeneous Reservoir
Authors: Al-Marzouqi Mariam , Al-Zaabi Najla , Schaeffner Anne , Al-Marasy Hatem 
Published: February 2011

Abstract
The Upper Jurassic formation in Offshore Abu Dhabi is formed of regressive cycles of sedimentation divided into four highly heterogeneous reservoirs (labelled Zones A through D) made up of dolomites/limestones/anhydrytes alternations. In these reservoirs, a fairly dense fault network can also affect fluids movements. Down-dip gas injection is one of the options currently being screened to sustain long term plateau duration of a major offshore Abu Dhabi field. In order to reduce uncertainties related to sweep efficiency in this complex environment, a gas injection pilot, made up of 2 gas injectors and 2 observers, was initiated late 2004.
The Pilot objectives were to: Quantify the impact of tertiary gas injection in lowest Zone D water flooded sub-reservoirs,Evaluate at microscopic scale the remaining oil saturation after gas FRONT,Evaluate the vertical and areal sweep efficiencies,Assess performance of oil producers associated with down-dip gas injection,Evaluate gas injectivity in the pilot area.
A full integrated monitoring and data gathering plan covering all formation reservoirs in the area of the pilot was implemented at project start, including: Extensive data acquisition on newly drilled wells: CMR, FMI, MDT, cores,Tracer injection and analysis,Regular time lapse Cased Hole Neutron and Saturation Logs on observer wells,Interference test between injectors and producers,Regular shut-in bottom-hole pressure data,Frequent production tests including gas sampling for tracer detection and chromatography analysis.
A full integration of all available data led to build a comprehensive and consistent understanding of gas movement and impact over pilot life: Tracer confirmed that gas has been detected in all upper sub-zones (A – D), suggesting vertical communication within the pilot area.Significant vertical differential pressure depletion has been observed between zones.Gas movements are mostly governed by heterogeneities in a multi-layer reservoir that showed the influence of the related fault system and differential pressure depletion.
RST time lapse logs show that microscopic sweep efficiency has been improved by gas injection in water swept zones. This will be confirmed by coring of the observer side track hole planned soon.
Coupled Thermodynamic-Flow Model Simulator for Inorganic Scale Deposition Calculation
Authors: Yee Hon Vai , Foo Khor Siak 
Published: February 2011

Abstract
Every year, millions dollars of money have been spent to remove and inhibit scale deposition in upstream oil industry. Hence it is important to have reliable predictive software to gauge the risk of scaling tendency of a production facility. Several approaches are established to model the scaling tendency during oil recovery. The most conventional models consider the concepts of phenomenological and equilibrium thermodynamic. Both methods are static modeling of an aqueous solution that predicts the scaling tendency at given temperature and pressure. If the scaling assessment is to perform on a producing well where the water composition, three phase (gas-water-oil) distribution and physical conditions (temperature and pressure) are varied at different location, the evaluation process becomes very tedious and impractical.
Therefore, a dynamic scaling modeling instead of static modeling method is required. For the reasons that in addition to serve as a tool to alarm the risk of scale precipitation, it also indicates the amount of scale precipitated and the likelihood deposition location to enable employment of pro-active preventive treatment at early stage. A coupled thermodynamic-flow model simulator is proposed to accurately determine the scaling tendency, quantity and location of inorganic scale deposition in production tubing under flowing condition. This model will couple the effects of thermodynamic equilibrium and kinetic for flow in a producing tubing. This is a major advance on prior state-of-the-art static models that normally predict the scaling tendency for single temperature and pressure input.
A modeling framework is presented in this paper. The proposed scheme in developing the thermodynamic-flow model is described. A number of engineering conceptions were reviewed and all the elements that become the foundation of this thermodynamic-flow model were discussed.
The advantage of having this thermodynamic-flow model is a better flow assurance management, in which scale prevention and treatment design can be refined, leading to unnecessary production lost and reduce treatment cost.