bluuebunny/crossref_metadata_2025_split huggingface dataset:
Perforating Monobore Completions Offshore: An Efficient, Safe and Optimal Approach
Authors: Long T. , Price P. , Kritzler T. , Gilliam B. , Jaime O. F. , Lobo J. M. , Bayer J. E. , Ritchie - Chevron J. , Khong C. K. , Malone S. G. , Baumann C. E. , Martin A. J. 
Published: June 2014

Abstract
Monobore completions have been installed in wells as far back as the 1980's. Early examples were reported in several SPE papers by companies such as Santos, Total and Unocal (now Chevron). The main drive being reduced drilling and completion costs. Perforating monobore completions is also not new and there are several methods to deploy guns into these types of well completions under various conditions (underbalance, overbalance or dynamic underbalance).
Reservoir performance can be optimized through perforation modeling where analysis has shown that a tailored Dynamic Underbalance (DUB) approach can deliver productivity gains from 5% (shallow mud filtrate damage) to 40% (deeper mud filtrate damage) higher than traditional perforation techniques. This is a data driven optimization based on field data such as zonal permeability, pressure, temperature, fluid shrinkage factor, fluid viscosity, GOR, wellbore trajectory and completion design.
To achieve maximum gain, multiple perforating runs on wireline are required; however this approach is often discounted (with well life production sacrificed) in order to achieve rig efficiency targets within the constrained economics of monobore completions, and to limit HSE exposure. This paper discusses a pragmatic approach to perforation optimization focusing on the specific alignment of economic, technical and safety related aspects within oilfield operations.
The context of this approach applies to the techniques used to avoid rig critical path altogether, thus removing rig cost from the equation and refining the approach through a data driven workflow utilizing acquired DUB pressure data. This approach describes the combination of the key components in detail, including latest shaped charge design and perforating technology, workflow optimization, operational risk and execution approach.
Results within this case have led to a standardized workflow within monobore completion delivering more than 24 days in operational savings over a 12 month period, and post perforation nodal analysis showing gains of up to 40% within a mature asset.
Restriction of Water Production in Gas Wells by Induced Phase Inversion: Field Case Studies
Authors: ILakatos I. , Lakatos-Szabo J. , Szentes G. , Vagó Arpad 
Published: June 2014

Abstract
Water shutoff treatments need different approach and chemicals in gas and oil fields due to the inverse mobility ratio. Therefore, the primary aim of the research project was to develop special treating solution, which may form barrier phase against the flow of water by in-situ mixing of the treating fluid with formation water. As a novelty, water sensitive petroleum-based solutions were developed, which are stable until they are contacted with water. The induced phase inversion of such metastable systems restricts the water flow by 80-90% in sandstone cores through evolving extremely high viscosity in the mixing zones. Optimizing the composition of the treating fluid containing environmentally friendly chemicals the method was qualified as matured for field pilot tests.
Evaluating the production history of possible alternatives, two gas producing wells were selected for the pilot. The wells are operating in different layers of the largest, stacked Hungarian oil and gas field. Prior to treatment, in both cases, the gas rate dropped significantly; meanwhile the water production rapidly increased to 120 and 150 BPD, respectively. The injection protocol started with partial reduction of water saturation in the nearby zone of wells by injection of water-miscible organic solvent driven deeply into the reservoir with N2. Afterwards, the petroleum bulk solution containing tenside and fatty acid ester in appropriate concentration was injected. Injecting 40-50 m3 treating solution, nitrogen drive served again to reach deep penetration of treating solution. Monitoring the wellhead pressure it was clearly indicated when the induced phase inversion started to build-up resistance against the water flow. Applying short shut-in time, transient production period was observed, which was followed by gradually increasing gas production with water-free and reduced water influx. The preliminary data firmly proved that the unique water shutoff technology might open new vistas reservoir conformance control in gas fields.
Avoiding Damage Associated to Produced Water Use in Hydraulic Fracturing
Authors: Fedorov Andrey , Carrasquilla Juan , Cox Angelica 
Published: June 2014

Abstract
The pressing water concerns of tomorrow demand that we target our time and technology in order to improve the fluid mixtures applied in fracturing operations. This challenge is intensified by the concomitant need to make use of produced water. Compelled toward this alternative as we continue to extract our remaining resources from the ground, we must account for the fact that the water we use will invariably decrease the strength of the composite fluids. Therefore, new chemicals are required to ensure stable results when testing these fluids.
Fresh Water scarcity across much of the Permian Basin is particularly critical and necessitates the pumping of produced water, thereby conserving dwindling reserves. The major problem with this approach is the need to balance the fluid recipe with chemical additives. Produced water is highly ionized and as such becomes less stable at heated temperatures, giving a smaller window to adjust chemicals for a precise formula. Hence, an innovative chemical solution is indispensable. A scale inhibitor was found to prevent scale deposition by sequestering the cationic scale-forming ions, and distorting the crystalline lattice structure. What is more, this product exhibits good thermal stability and is also very effective ion stabilizations. Accordingly the novel scale inhibitor was implemented and successfully pumped for more than 200 stages in West Texas.
A Comprehensive Geochemical-Based Approach to Quantify the Scale Problems
Authors: Kazemi Nia Korrani Aboulghasem , Sepehrnoori Kamy , Delshad Mojdeh 
Published: June 2014

Abstract
Oil-field scales result from changes in the physicochemical properties (pH, temperature, pressure etc.) of the produced fluids and/or due to the chemical incompatibility between waters having different compositions (e.g., formation brine and injection brine). Nevertheless, the comprehensive modeling and prediction of such phenomena remains a challenge, due to the complexity of the precipitation kinetics and chemical reaction processes that occur in the reservoir. Hence, it is the case that often reactions in the reservoir are not considered on evaluation of the scaling tendency, probably because they are difficult to measure and also, to model the calculations considerable effort and expertise is required.
Since no comprehensive geochemical-based modeling has been applied in this research area, in this work, a previously developed robust, accurate, and flexible integrated tool, UTCHEM-IPhreeqc, is used to model the comprehensive geochemistry to predict scales problem for field scale applications.
IPhreeqc, the United States Geological Survey geochemical tool, is able to simulate both homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under non-isothermal, nonisobaric and both local-equilibrium and kinetic conditions. Through coupling of IPhreeqc with UTCHEM, The University of Texas at Austin research chemical flooding reservoir simulator, the entire geochemical capabilities of IPhreeqc can be used in a multi-dimensional and multiphase reservoir simulator for comprehensive reactive-transport modelings.
In this paper, the importance of ion activities, temperature, and pressure in the reactive-transport modeling is emphasized by performing several sensitivity analyses. Oilfield scale is quantified by including the effect of dissolution or precipitation of all possible minerals (either initially present or subsequently precipitated by injecting an incompatible water) on the reservoir petrophysical properties (e.g., porosity). Three common permeability-porosity approaches (Modified Fair-Hatch, Kozeny-Carman, and Verma-Pruess models) are then implemented in the UTCHEM-IPhreeqc simulation tool to model the effect of scalings on the reservoir permeability. To show how well this integrated tool can be applied for field scale applications, a synthetic five-spot pattern is presented using several water compositions.
Reconciliation of Fracture Performance and Fracture Geometry with Design
Authors: Guk Vyacheslav , Bychina Maria , Wolcott Don , Economides Michael J. 
Published: June 2014

Abstract
For more than 50 years a vision of a hydraulic fracture that is vertical with two symmetrical wings has been accepted by two highly diverse sciences in petroleum production: fracture mechanics and production/reservoir engineering models. The fracture in both sciences has a height, a length tip-to-tip, and an average width.
A fracture propagation model is usually employed to determine fracture dimensions. Linear elastic fracture mechanics points towards a relationship between fracture length (and, implicitly, height) and fracturing pressure. Therefore, pressure analysis during execution is supposed to 1) determine the generalized fracture geometry and 2) to quantify fracture dimensions such as length and width.
Once the well is put on production, the fracture geometry can be determined either through a well test or through long-term production data analysis or both. The models employed for this exercise have been in wide use and have been credited with considerable success in hydraulic fracture treatment evaluation. Pressure patterns would lead to the determination of the apparent fracture half-length and fracture permeability-width product. Unfortunately, often there is a discrepancy to a severe discrepancy in the fracture dimensions obtained from the two methodologies.
We present here several theories describing the discrepancy and we quantify the impact of reservoir and fracture parameters. These include reservoir areal permeability anisotropy, damage to the proppant pack, discontinuity in fracture conductivity and, of course, turbulence effects. We are applying this approach to 23 hydraulically fractured wells in a less-than 1 md oil and gas reservoirs in Western Siberia and achieve reasonable reconciliation between the results of the diverse methods of fracture geometry determination and the impact of reservoir and fracture variables. Fracture treatments, designed for other wells in the field take these conclusions into account.
Environmentally Responsible, Catalytic Breakers for Alkaline, High-Temperature Fracturing Fluids
Authors: Gunawan Stanley , Armstrong C. David , Qu Qi 
Published: June 2014

Abstract
The development of new environmentally responsible breakers for use in high-temperature fracturing fluids (≥ 250 °F) was sparked by efforts to minimize environmental risks from oilfield chemical systems. A novel type of breaker system, derived from biological sources and displaying catalytic activity, was discovered and tested for its ability to reduce the viscosity of polymers commonly used in hydraulic fracturing applications. The breakers are miscible, catalytic, biodegradable, and come from sustainable resources. Additionally, these breakers do not display the thermal denaturation limitations of enzyme breakers.
Two novel, environmentally-responsible breakers, UB-1 and UB-3, were tested for their ability to break the viscosity of crosslinked guar and derivatized guar polymers at temperatures of 250, 275, and 300 °F. UB-1 was more effective in breaking crosslinked guar polymers. UB-3 was more effective in breaking crosslinked derivatized guar polymers (i.e. carboxymethyl guar).
As hydraulic fracturing technology is used in more challenging reservoirs, the need increases for effective breakers that function at elevated temperatures. At high temperatures, oxidative and enzyme breakers have drawbacks: Oxidative breakers become too reactive and enzymes denature. Our previous paper (SPE-159396) detailed the efficacy of the new breaker technology at mid-range temperatures (175 to 225 °F). This paper will explore the use of these breakers at higher temperatures.
This paper will include the testing program for the viscosity-reducing ability of these novel breakers in guar and carboxymethyl guar in alkaline and high-temperature conditions (&gt; 250 °F). They will also be compared with oxidative breakers. Finally, the paper will include recommendations for field applications, including economic impacts on fracturing fluid systems.
Formation Damage From Pipe Dope: How Bad Can It Get?
Authors: Castiñeiras Tomás , Goretta Emiliano Actis , Funes Alejandro , Figini Fernando , Wang Xiuli , Economides Michael J. 
Published: June 2014

Abstract
Laboratory work has shown that pipe dope, routinely used during well construction can penetrate and damage relatively high-permeability formations. Previous laboratory and field studies showed that dope-induced formation damage is severe (more than 99 percent). However that earlier work using cores up to 240 md demonstrated that dope particles would stay at the front face of the cores, forming a filter cake and not penetrate the rock matrix.
If the well is put on injection service and in the case of workovers such as matrix stimulation treatments, the formation damage caused by pipe dope will almost guarantee operational failure. However, for production, the dope can be readily swept to the surface and its impact would be minimal.
What would be the situation in higher permeability rocks if dope particles were to penetrate the formation in which case they may not be removed through flowback?
The objective of this work is to evaluate the magnitude of formation damage by pipe dope in higher permeability sandstone samples of 1,000 md in two injection tests of commonly found concentrations in field operations.
Results show clear penetration of the core matrix, manifested by large pressure gradients measured along the core. The dope, although in relatively small concentrations causes a considerable permeability reduction and, implicitly, a marked reduction in connected porosity. The latter is particularly important because small quantities can cause very large damage, unlike drilling mud which would require large losses into the rock to cause comparable damage.
The good news is that dope-free connections for casing & tubing can be used to avoid thread compounds and eliminate well damage as they produce zero effluents. Dope-free connection can also improve the efficiency and reliability of the operation itself, removing a cumbersome, albeit routine job, a major advantage in drilling operations. Because of obvious economic considerations these benefits will be more profound in a deepwater environment.
Hybrid Matrix Acidizing Techniques Successfully Stimulate Geothermal Wells in Latin America
Authors: Exler Victor A. , Cisneros Fernanda T. , Quevedo Manuel A. , Milne Arthur , Cornejo Sergio 
Published: June 2014

Abstract
Mexico, the world's fourth largest producer of geothermal energy, generates 965 MW of electricity. One field alone produces 195 MW. However, to maximize the steam production of geothermal wells it is often necessary to perform matrix stimulation treatments. The temperature and mineralogy of the naturally fractured volcanic formations and scales tendency present some unique challenges.
The potential of many geothermal wells is limited by formation damage. Drilling fluid invasion, fines migration, silica plugging, and scaling being the most common. Mineral scale deposition occurs in the wellbore or in the natural fractures through which water is either injected or produced. In producing wells, the composition of scale is dependent on the mineralogy of the metamorphic formation. In injection wells, the scale is dependent on the composition of the injected water. With limited information regarding the mineralogy of the scale and the formation, many conventional matrix treatments are unsuccessful.
A hybrid design methodology, combining sandstone and carbonate acidizing techniques has proved to be the first step to successfully treating Mexico's and Central America's geothermal wells The treatments are then further customized for each field to optimize productivity and injectivity. The final fluid composition is often very different from that used in conventional treatments due to different selection criteria and placement techniques.
Identifying and understanding this concept has helped producers in Mexico and Central America increase their energy production per well by an average of 65%. While in some cases energy production has increased 300%.
The hybrid design methodology has been successfully used to stimulate more than 50 geothermal wells in Mexico and Central America - Humeros (Puebla), Tres Virgenes (Baja California), Azufre's (Michoacan), Berlin (El Salvador) and San Jacinto (Nicaragua). The results of these campaigns demonstrate that it is possible to consistently improve the productivity of geothermal wells through the correct treatment.
Design Considerations and Qualification Testing of High Density Oil-Based Screen Running Fluids for an HPHT Gas Development
Authors: Han L. , Hicking S. , Twycross J. , El-Jamali S. , Patey I. , Green J. 
Published: June 2014

Abstract
This paper describes the design and qualification testing of high density oil based screen running fluids for an HPHT subsea gas field development in the Norwegian Sea.
The field of interest contains gas bearing sandstones with permeabilities up to 5-10 Darcy buried at greater than 5000 m at high temperature and pressure (185 °C, 830 bar).
The wells are designed to be completed with standalone screens. However, running screens in high density OBM has been a challenge for the industry due to the high solids load of such fluids.
To qualify an HPHT screen running fluid, crucial to the economical development of this field, a rigorous fluid testing program was designed and carried out. The main drivers for the fluid qualification are to ensure that:
The fluid is stable at downhole temperature to allow the running of the screens to bottom without plugging The fluid should remain mobile to allow easy backflow after a 28-day static period to allow subsequent well completion operations and back flow of the wells The fluid should not plug the screens after the 28-day static period
The fluids were first designed and tested in vendor laboratories to ensure good long term stability and mobility. This was followed by internal confirmation testing by the operator. Final qualification at a third party facility for stability and mobility was carried out at simulated downhole conditions using a purpose built HPHT cell incorporating a sand control screen. The results of the qualification program showed that a 1.90 sg oil-based fluid containing fine barite can deliver a feasible solution to the completion challenges for the HPHT field development. The designed fluids are stable, easy to backflow and will not plug the sand control screens. The learnings from this study will also be presented.
Real Time Slickline: Unlocking Additional Production With Reduced Uncertainties in Limited Space Platforms
Authors: Razak M. Abdul , Dasan L. M. , Effendi S. Mohd , Rakela T. I. 
Published: June 2014

Abstract
Platforms with limited crane capacities and restricted space in which to set up the necessary well intervention equipment are challenges that the industry is facing increasingly in offshore environments. Operators are having to either compromise on operational efficiency and certainty through the use of memory based slickline conveyance applications (e.g. slickline perforating without real time correlation) or are having to rely on more costly solutions utilizing a multitude of equipment and leveraging workover rigs in order to accomplish their intervention campaigns.
Real time slickline’s light, minimal foot print and modular make up coupled with its digital telemetry enablement allows operators to access wells and perform conventional slickline operations, plus perforating, plug setting and production logging, all with downhole in-situ information available on surface in real time, bringing huge operational efficiencies as well as reducing considerably the risks and uncertainties of the intervention programs being undertaken.
Interventions executed using real time slickline have proven to be a safer, more efficient and more cost effective way to conduct operations by having full realtime control of its downhole tools and periphery sensors. It reduces the associated risks of having to mobilize and switch between electric line and slickline units, equipment and personnel in the cases where the scope of the intervention programs can be fully covered by real time slickline’s capabilities. Furthermore, its minimal weight and footprint enables intervention operations where space and crane capacities make slickline the only choice of conveyance.
Comprehensive Analysis of Metal-to-Metal Lubricants in Oil Shale Plays
Authors: Barraez Rair , Noland Justin , Matheus Daniel , Spence Zach 
Published: June 2014

Abstract
Metal-to-metal lubricants used within the Coiled Tubing (CT) industry have become an essential resource for the successful completion of a variety of operations, most notably extended reach practices. A vast selection of metal-to-metal lubricants exist within the industry, which provides an abundance of options for CT applications. However, the effectiveness of these lubricants based on different well parameters is not well understood.
The objective of this study is to provide a quantitative analysis comparing the friction reducing characteristics of various CT metal-to-metal lubricants used in optimized extended reach practices.
Fourteen different lubricants commonly used in the Eagle Ford and the Bakken resource plays were tested using an OFITE EP (extreme pressure) and lubricity tester to determine their respective lubricity coefficient and film strength. The lubricity coefficient test used a torque arm which applied 150 in-pounds of force (the equivalent of 5,000 to 10,000 psi on the intermediate fluid) between two hardened steel surfaces (a block and a ring) rotating at 60 RPM. The EP test produced an indication of the film lubricant strength by applying a measured force to a torque-sensitive bearing cup with the torque arm. The EP test was performed at a high shear rate of 1,000 RPM with fluid pressures ranging from 5,000 to 100,000 psi between the steel surfaces.
Tests with multiple solutions and various conditions were conducted to provide a better understanding of how the lubricant reacts in field applications. Each lubricant was mixed with fresh water, brine fluid, friction reducer, and 15% HCl fluid at different temperatures.
The effectiveness of the top-performing metal-to-metal lubricants was validated by comparing the laboratory results with field data and computer modeling. The outcome of this analysis was used in conjunction with previously completed extended reach studies to further understand and improve the effects of metal-to-metal lubricants in CT operations.
This paper provides a comprehensive analysis of the performance of the different metal-to-metal lubricants based on the applications and well conditions. A more in-depth understanding of the lubricants will help to improve accuracy when modeling and designing extended reach CT operations, which will result in improved overall efficiency.