bluuebunny/crossref_metadata_2025_split huggingface dataset:
Results of Jan. 25, 2011 IADC Shale Drilling Technology & Challanges Workshop
Authors: Torkay D. , Brakel J. , VanMarel H. , Geehan T. , Shelton A. , Reid D. , Killalea M. , Womer K. 
Published: June 2014

Abstract
This paper presents the results from a workshop on Shale Drilling Technologies and Challenges held in Houston on January 25th, 2011. This workshop, sponsored by the IADC Advanced Rig Technology, Future Technology Subcommittee, brought technology leaders and engineers together to discuss issues related to North America Shale Drilling. Led by specialists with operating, contracting and technology companies, the workshop goal was to educate the industry regarding existing technologies and challenges. A unique aspect of this workshop featured results of sociology studies on the onshore O&G industry and the perceived challenges of drilling in urban environments. This is the second of a series of planned workshops to address technology needs which were identified in an industry survey conducted by the IADC ART committee in 2009 and reported in SPE 128953.
Improving Well Productivity/Injectivity on Deepwater Offshore Horizontal Drains
Authors: Menezes C. , Benchimol L. , Mcewan M. , Ohwo A. , Poinset V. , Sutherland G. 
Published: June 2014

Abstract
Near-wellbore formation damage and high mechanical skin is a concern on the deep water horizontal wells drilled and completed off the West Coast of Africa. Due to the typically unconsolidated sandstone reservoirs, sand control is essential, either Stand Alone Screens (SAS), or Open Hole Gravel Pack (OHGP) sandface completions are run to contain the sands. Although the drilling mud is replaced by sieved mud, and carefully controlled for solids, plugging can still occur through insufficient degradation of the filter cake. In addition, losses during the drilling of the drain and even the screen size vs. open-hole diameter can also have a significant impact.
Productivity impairment issues originally encountered on Rosa producer wells (Deep offshore Angola, Block 17) led to the development and testing of a unique micro-emulsion technology in 2006, for use with coiled tubing deployed remedial treatment inside the screens. The ‘cake breaker’ system, a stable blend of surfactant, acid and brine, was tailored for the mud system used, and designed for fast acting remedial treatment. The results of the Rosa intervention treatments proved successful and additional testing was carried out in 2007 / 2008 to benchmark the tailored system to other products on the market. The tailored system remained the system of choice and the same remedial treatment formulation was applied on some of the earlier Dalia wells (producer & injector). Treatment results were positive, and have improved further still by optimizing the formulation.
Preventative treatments have also been developed, using various deployment methods. The evolution has been towards a displacement of the mud in the open hole / screen annulus, prior to displacing inside the screens. The results have been mixed however, with the remedial treatments generally proving more effective than the preventative treatments. This paper looks at the experience gained on the deep water horizontal wells in Block 17 off the west coast of Angola, namely the Rosa, Girasol, Dalia and more recently the Pazflor field. The differences in results are evaluated and the various methods and lessons learnt are presented.
Foaming Aqueous-Based Curable Treatment Fluids Enhances Placement and Consolidation Performance
Authors: Nguyen P. D. , Rickman R. D. 
Published: June 2014

Abstract
Conventional solvent-based resins (SBRs) have often been used to resolve solids-production problems in producing wells by coating the particulates, such as formation sand, fines, and proppant, with a curable resin to hold the grains together without reducing the treated pack’s permeability. However, the SBRs have low flashpoints that can present safety issues during storage, handling, and well-completion operations. These resin systems have been typically applied in short intervals of less than 30 ft and have had limited success in longer intervals. With the recent development and applications of aqueous-based resins (ABRs), these drawbacks have been overcome. Because solvent-based chemicals are replaced with aqueous brines as carriers in treatment fluids, ABRs have high flashpoints, similar to those of water. Additionally, because ABRs are aqueousbased fluids, they can be foamed so that the operator may simply bullhead the fluid directly into the wellbore to treat long intervals without requiring a rig or zone isolation packers.
This paper presents the results of laboratory experiments aimed at understanding and quantifying the performance of ABR treatment fluids in consolidating weakly or unconsolidated formation sands or loose proppant packs. Consolidation strengths and scanning electron micrographs of the treated formation sand or proppant packs were analyzed to identify the mechanisms behind the treatment fluids in providing cohesion between particulates and how the pore channels within a pack matrix remain open, minimizing permeability loss. Both foamed and nonfoamed ABRs were determined to provide effective consolidation levels to the treated formation sandpacks, regardless of whether foamed or not, aqueous post-flush fluid was applied. However, only foamed ABRs allowed resin to remain on the proppant after the treated pack was overdisplaced with nitrogen gas or a nonaqueous fluid, resulting in high consolidation strength and retained permeability.
Foaming ABRs enhances the effectiveness of their placement into formation intervals by providing an effective means for diversion and better coverage, and extending treatment-fluid volume. When applied using bullheading or coiled tubing, potential applications of ABR systems include primary or remedial treatments of weakly or unconsolidated formations for sand control or fines stabilization and remedial treatments of propped fractures for proppant-flowback control.
A New Emulsified Acid to Stimulate Deep Wells in Carbonate Reservoirs
Authors: Sayed M. A. , Nasr-El-Din H. A. , Zhou J. , Holt S. , Al-malki H. 
Published: June 2014

Abstract
Acid treatments in high temperature deep wells drilled in carbonate reservoirs represent a challenge to the oil industry. The high temperature of deep wells requires a special formulation of emulsified acid that can be stable and effective at such high temperatures. At these high temperatures, both the reaction rate between acid and rock, and corrosion rate of tubulars are high. This fact makes protection of tubulars and reducing the reaction rate between rock and acid challenging. At temperatures above 200 °F, there is a need to add more corrosion inhibitor and corrosion inhibitor intensifier, which increases the cost of the treatment too much.
A new emulsifier was developed and used to prepare emulsified acids that can be used in stimulating deep wells drilled in carbonate reservoirs. In the present paper, the rheology of the new acid is compared to the rheology of another system formulated by a commercial emulsifier that has been used extensively in the field. All emulsified acid systems were formulated at 0.7 acid volume fraction, and the final HCl concentration varied from 5 to 28 wt% HCl. The rheology measurements were conducted at temperatures up to 300 °F for emulsifier concentration ranges from 0.5 to 2.0 vol%. The reaction between emulsified acid and rock was studied using a rotating disk apparatus at 230 °F and rotation speeds up to 1,500 rpm. A core flood study was conducted in order to study the efficiency of the new emulsified acid to create wormhole, and increase the efficiency of the treatment, especially at a high temperature (300 °F).
The results showed that the new emulsified acid system had higher thermal stability and higher viscosity than the old one. Also, the new emulsified acid system created deep wormholes at all injection rates covered (0.1 cm3/min up to 10 cm3/min), with no face dissolution encountered during acid injection. The reaction rate between emulsified acids formulated using the new emulsifier was measured using a rotating disk at 230 °F. The dissolution rate varied between 2.57E-6 gmol/cm2.s at 100 rpm and 1.09E-5 gmol/cm2.s at 1500 rpm. The diffusion rate was measured for these emulsified acid systems and was found to be around 2.73E-7 cm2/s. From these results, the new emulsifier can be used in formulating emulsified acid systems that can be used effectively in stimulation of high temperature deep wells. This paper summarizes the results of testing the new emulsified system, and recommends its use for field application in deep carbonate reservoir.
Effective Matrix Stimulation of High-Temperature Carbonate Formations in South Sumatra Through the Combination of Emulsified and Viscoelastic Self- Diverting Acids
Authors: Madyanova M. , Hezmela R. , Artola P. , Guimaraes C. R. , Iriyanto B. 
Published: June 2014

Abstract
The biggest challenges for successful matrix acidizing treatments on carbonate formations are the creation of an effective network of wormholes and obtaining uniform coverage. Typical matrix treatments often require low injection rates, and therefore hydrochloric acid cannot be used alone because rapid acid spending severely limits the acid penetrationat elevated temperatures. This high reaction rate causes face dissolution, fails to create a wormhole network long enough to effectively bypass the damaged zone around the wellbore that leads to the creation of dominating wormhole.
The Sungai Kenawang (SKN) onshore gas-condensate field, located at the southwest part of the Jambi Merang block in the South Sumatera Province, is a carbonate buildup, which is part of an isolated bank containing a group of buildups. The Baturaja formation, located at depths around 7,000 ft, is a thick gas condensate reservoir with permeabilities in the range of 10 to 350 mD, bottomhole temperatures range of 280 °F and 350 °F and the presence of H2S. The standard method used to stimulate these carbonates was pumping 15% gelled hydrochloric acid through coiled tubing. Production logs and pressure build-up analysis have shown positive skin values post stimulation and that the production was mainly coming from the upper zones, with minimal contribution from the lower zones.
This paper describes the application of a high temperature, highly retarded emulsified acid system that slows the reaction times by a factor of 5 to 15 compared to conventional HCl systems. The emulsified acid system combined with a selfdiverting viscoelastic surfactant based acid was able to achieve complete stimulation of a 197 ft long perforated interval without the need of coiled tubing. A pressure buid-up test showed a post-stimulation skin value of – 3.3 and the production log analysis demonstrated complete and uniform zonal coverage with the upper zones contributing with 53% of the total well production and the lower zone with 47%.
Mitigation of Calcium Sulfate Scale Formation When Seawater Is Used To Prepare HCl-Based Acids
Authors: He J. , Mohamed I. M. , Nasr-El-Din H. A. 
Published: June 2014

Abstract
The damaging effect of calcium sulfate precipitation on the permeability of carbonate cores when mixing hydrochloric acid with seawater for matrix acid treatments has been identified in our recent work (SPE 143855). The objective of this work is to mitigate calcium sulfate precipitation by using a suitable scale inhibitor in hydrochloric acid. Another objective is to determine the scale inhibitor type, concentration, and whether it is needed in the preflush or post-flush stages.
Core flood tests were conducted using Austin Chalk cores(1.5 in. × 6 in.) with a permeability of 5 md, to investigate the effectiveness of scale inhibitor. A synthetic seawater was prepared according to the composition of seawater in the Arabian Gulf. Calcium, sulfate ions, and scale inhibitor concentrations were analyzed in the core effluent samples. The minimum concentration of scale inhibitor was determined over a wide range of temperatures (77 to 210°F).
A scale inhibitor (sulfonated terpolymer) was found to be compatible with hydrochloric acid systems, and can tolerate high concentrations of calcium (30,000 mg/l). Analysis of the core effluent indicated that the new treatment successfully eliminated calcium sulfate scale deposition. The concentration of scale inhibitor ranged from 20 to 250 ppm, depending on the scaling tendencies of calcium sulfate. This work confirms that an appropriate scale inhibitor can be added to acid, to avoid calcium sulfate precipitation when seawater is used to prepare hydrochloric acid for matrix acidizing.
Observation of Gel Filter Cake Recovery by Dissolution in Flowback Fluids
Authors: Gdanski R. D. , Bryant J. E. 
Published: June 2014

Abstract
Wells completed in tight-gas sands often produce below expectations after fracture stimulation, with gel filtercake damage cited as a major cause of poor performance. These filtercakes have historically been viewed as immobile and insoluble in flowback water. However, recent field observations demonstrated conclusively that borate-crosslinked filtercakes delink and redissolve in flowback water. A fracture cleanup and chemistry simulator (FCCS) was used to discover and develop an appropriate rate law for the dissolution of gel filtercakes in flowback water. The simulator was validated by matching the observed gel contentin the flowback waters from a fracturing treatment.
Previous work demonstrated that behavior of gel filtercakes in proppant packs from fracturing treatments was more complex than expected. Particularly interesting were recent observations of significant concentrations of gelling agent across several hundred barrels of flowback fluid from a fracturing treatment with good documentation. Ionic composition of the well returns was first matched with the FCCS. Matching of the gel recovery profile required discovery and development of a rate law for dissolution of gel filtercake by water inflowing from the fracture face. Potential rate laws using flow of water down the length of the fracture were not able to match the observed profile. Parametric studies were then conducted and showed a gel displacement regime and a dissolution regime for gel recovery, with the controlling regime dependent on gel phase saturation in the proppant pack. The gel phase saturation in the proppant pack should be 50% or less to be in the dissolution regime for efficient gel recovery.
Converting Static Friction to Kinetic Friction to Drill Further and Faster in Directional Holes
Authors: Skyles Lane P. , Amiraslani Yosef A. , Wilhoit James E. 
Published: June 2014

Abstract
Since the dawn of directional drilling with downhole mud-motors, Operators and Directional Drillers (DD’s) have been continuously frustrated by the difficulties encountered during "sliding" operations. The challenge has always been how to overcome static friction between the drill pipe and the hole wall while the pipe is not rotating. Overcoming this static friction becomes more and more difficult as the DD leaves 0° inclination and works toward 90°. Some of the challenges to overcome are weight stacking, sinusoidal and helical buckling of the drill pipe, stick slipping, inability to hold tool face, slow ROP, etc. The good news is that static friction while sliding can now be greatly reduced by effectively converting it to kinetic friction; kinetic friction being much less inhibitive to drilling operations.
The following paper introduces a drilling tool that breaks static friction while sliding. This tool has repeatedly shown to break this friction without detriment to other downhole drilling tools or operations. Drilling with kinetic friction instead of static friction saves time, money and frustration. The Introduction of the following paper demonstrates the stated problem by showing the basics of friction resistance in the drill string while directionally drilling. The paper then describes this downhole tool and how it cures symptoms that frustrate the DD. The final section will present a Case Study conducted in a Barnett Shale horizontal drilling application in Tarrant County, Texas. It will strive to graphically illustrate and emphasize the effect of the tool on drilling operations.
An Improved Dynamic Well Control Response to a Gas Influx in Managed Pressure Drilling Operations
Authors: Bacon William , Tong Albert , Gabaldon Oscar , Sugden Catherine , Suryanarayana P. V. 
Published: June 2014

Abstract
Managed Pressure Drilling (MPD) offers the capability to control an influx dynamically, without conventionally shutting-in. Some current methods use applied-back-pressure (ABP) to force flow exiting the annulus to equal flow entering the drill-pipe, which is interpreted as influx cessation. However, solely ensuring flow continuity does not imply influx cessation, unless the annular fluids are incompressible. In this work, the impact of compressibility on dynamic well control is investigated. The transient response of compressible, multiphase flow in the annulus is examined using mass conservation over a control volume.
Limitations of Qout = Qin indicating influx cessation are explored, and an improved ABP dynamic well control technique is proposed. The new technique is applicable in MPD operations where conditions warrant dynamic well control rather than conventionally shutting-in.
It is shown that with some current methods, influx may not cease once flow out is constrained to equal flow in. It is also shown that in some situations, influx ceases before flow continuity is achieved, resulting in excessive bottomhole pressure. These outcomes are consequences of in-situ gas compressibility, making it invalid to solely rely on Qout = Qin to indicate influx cessation. The proposed technique is shown to offer accurate determination of influx cessation, even when compressibility is significant. New pressure and pressure derivative based parameters that carry the signature of influx cessation are defined. It is shown that consideration of these parameters appreciably increases the likelihood of successful well control. Several examples are shown to illustrate the new approach with the use of the new signature parameters.
Numerous transient, multiphase flow simulations have supported the key analytical conclusions from this work.
The results of this work are expected to improve the reliability of dynamic well control using ABP during Managed Pressure Drilling operations. Further, the new signature parameters are easy to monitor and interpret, and together with flow rate provide valuable additional information to assist dynamic well control.
Hydrodynamic Loads, Soil and Structure Interaction in Conductor Design for Offshore Platforms and Jack-Up Rigs
Authors: Pilisi Nicolas , Lewis David 
Published: June 2014

Abstract
The design of a conductor casing is significantly different than that of the other tubulars in a well. Conductors are drag-dominated structures that enable conducting drilling operations from offshore fixed platforms or jack-up rigs through the seawater column. To date, the majority of technical papers concerning conductor design have focused on a particular aspect of the conductor pipe but very few of them have detailed the design of conductors in response to the combination of hydrodynamic loads, external and internal loads acting on this casing string as well as the soil-conductor interaction.
This paper discusses the design of both platform conductors and jack-up supported conductors used in open water by first providing the essential steps (i.e. deriving and presenting equations) that need to be followed to ensure the structural integrity of the conductor casing along its entire length. Then, in order to illustrate the methodology, four case studies were performed to investigate the performance of well conductors at different shallow water locations (the Gulf of Mexico, South America, the North Sea and South-east Asia).
For all analyses, the conductor pipe has been checked for three failure modes: strength, stability and fatigue and finite element analyses have been computed to solve the hydrodynamic loading, the statically indeterminate problem and the complex soil-structure interaction. The results show that, in general, stability controls the conductor design which means that the conductor will buckle before it yields; and therefore, there is a requirement to apply tension at the Texas Deck for a jack-up. Also, in some instances (i.e. rougher water environments) or with smaller size conductors (13.375-in. and 20-in.), the fatigue analysis may become the most important failure mode for both the conductor pipe body and the connectors.
Special Considerations in the Design Optimization of High Rate, Multistage Fractured Shale Wells
Authors: Sugden Catherine , Johnson John , Chambers Mike , Ring Gary , Suryanarayana P. V. 
Published: June 2014

Abstract
Typical shale well completions involve massive, multistage fracturing in horizontal wells. Aggressive trajectories (with up to 20°/100 ft dog legs), multistage high rate fracturing (up to 20 stages, 100 bpm), and increasing temperature and pressure of shale reservoirs result in large thermal and bending stresses which are critical in the design of production casing. In addition, where cement voids are present and the production casing is not restrained during fracturing, thermal effects can result in magnified load conditions. The resulting loads can be well in excess of those deemed allowable by regular casing design techniques. These loads are often ignored in standard well design, exposing casing to the risk of failure during multi-stage fracturing.
In this work, the major factors influencing normal and special loads on production casing in shale wells are discussed. A method for design and optimization of shale well production casing design is then introduced. The constraints on the applicability of different design options are discussed. Load magnification effects of cement voids are described and a method for their evaluation is developed. It is shown that thermal effects during cooling create both bending stress magnification and annular pressure reduction due to fluid contraction in trapped cement voids. This can result in significant loads and new modes of failure that need to be considered in design. The performance of connections under these loads are also discussed. Examples are provided to illustrate the key concepts described. Finally, acceptable design options for shale well production casing are presented.
The results presented here are expected to improve the reliability of shale well designs. They provide operators with insight into load effects that need to be considered in design of production casing for such wells, and with options for adequate design.