bluuebunny/crossref_metadata_2025_split huggingface dataset:
Removing Mechanical Skin in Heavy Oil Wells
Authors: Dusseault Maurice B. , Davidson Brett C. , Spanos Tim J. 
Published: December 2007

Abstract
High-amplitude, low-frequency pressure pulsing was developed as a new oil well workover technique, and has been used in &gt; 40 heavy oil wells in Alberta and Saskatchewan during the period October 1998 to October 1999, with a good success ratio. The method is particularly effective in initiation sand production and in cases where mechanical skin arising from blocked perforations, immobilized fines and asphaltenes are responsible for a high skin factor.
Perforation blockage, restriction of near-wellbore flow paths through fines accumulation, pore throat precipitation of asphaltenes, and sand re-compaction around the well are all thought to be responsible for rapid production rate declines in many wells. In heavy oil wells, chemical treatments alone are rarely useful, but large physical perturbations of the material around the wellbore have been found to be effective in reestablishing production.
A downhole device was developed to apply large periodic pressure pulses to the perforation face. This device also permits injection of fluid at measured rates into the nearwellbore region while executing prolonged (9–12 hour) high-amplitude perturbation. The action loosens mechanical skin, allowing the source of flow blockage to be physically removed through remolding and liquefaction of the sand around the wellbore. This liquefied zone is produced when the well is placed back on production, and in most cases the well is rejuvenated. In some cases, wells that never produced economic rates of oil because sand influx could not be initiated were turned into reasonable producers after a pressure pulse treatment. The method can also be used to deliberately introduce treatment chemicals while reducing the negative effects of channeling and fingering, as the front of treatment fluid ingress is well dispersed by the pressure pulsing.
Development of a Downhole Scale Management Philosophy for Water Sensitive Reservoirs
Authors: Scott Graham C. , Littlewood Michael J. 
Published: December 2007

Abstract
Scale deposition in the near well bore and the production tubing of an oil production well can have a major impact on the productivity of the well. Normally, this problem can be avoided by pumping a concentrated solution of an aqueous scale inhibitor followed by displacement of the inhibitor into the reservoir with sea water. The scale inhibitor is allowed to absorb or precipitate in the reservoir so that when the well is returned to normal flow the scale inhibitor is able to desorb and inhibit scale formation over several months. However, there are many reservoirs that are water sensitive such that if an aqueous scale inhibitor treatment is deployed then severe productivity impairment can occur.
This phenomena occurs in Amerada Hess’s Scott & Telford fields where core studies have shown that severe productivity impairment would result if a well with a water cut of less than 30% was treated with an aqueous scale inhibitor treatment.
This paper describes the development of an effective downhole scale management strategy that allows scale control to be achieved without incurring major loss of productivity. The strategy was achieved by the sequential use of oil soluble scale inhibitors, aqueous inhibitors in conjunction with relative permeability modifying chemicals and micro-encapsulated scale inhibitors. This type of strategy would also be applicable to other fields where a water sensitive reservoir makes downhole scale control problematic.
Iron Release Following Mineral Dissolution Following Scale Inhibitor Application In a North Alaskan Reservoir
Authors: Hill P. I. , Graham G. M. , Dyer S. J. , Coleman J. 
Published: December 2007

Abstract
High levels of dissolved iron present in produced waters have caused concern in a number of wells in North Alaskan Reservoirs. In this paper, two dynamic "reservoir condition" scale inhibitor core flooding experiments have been conducted to simulate scale inhibitor treatments using a pre-selected commercial phosphonate based scale inhibitor. In these floods very high levels of iron were released during the chemical injection and shut-in stages (&gt; 450ppm in solution). Evidence from pre and post treatment SEM analysis revealed that the major cause for the excessive iron release was extensive dissolution of siderite, inducing considerable mechanical weakness of the core, which was particularly evident for core 1, and much less so in core 2. However, although both cores have similar percentages of siderite, it is the textural arrangement, which is of prime importance in relation to formation damage. In core systems where siderite supports many grain contacts any fluid/mineral dissolution reactions will significantly impair mechanical strength (core 1), potentially leading to sand production. Where siderite is enclosed within finer carbonate mud lenses, or is not grain supporting, the mechanical damage is much less severe (core 2). Reactions of siderite with the core are quite complex. In this paper we demonstrate the formation of an oxidised rim of hematite which surrounds remnant siderite, with voids present between it and the hematite rim.
The high levels of iron release recorded in such systems have considerable implications with regard to the effectiveness of the pre-selected scale inhibitor. Inhibitor performance tests for a range of generically different inhibitor clearly indicate that the performance of certain types of scale inhibitor products is significantly reduced in the presence of dissolved iron. These results concur with field experience where phosphonate based inhibitors (initially selected based upon performance in the absence of iron) have proven less successful in the field.
In summary it is evident that potential dissolution of iron bearing minerals, and the subsequent influence of dissolved iron on performance, has a significant bearing on scale inhibitor selection.
High Angle OHGP’s In Sand/Shale Sequences: A Case History Using a Formate Drill-In Fluid
Authors: McKay G. , Bennett C. L. , Gilchrist J. M. 
Published: December 2007

Abstract
Historically, application of open hole gravel packs have mainly been limited to completion of deviated and vertical wells. Other limiting factors affecting selection of this type of completion are reservoir quality and heterogeneity, or the need for selective completion. However, with an increasing number of high angle and horizontal wells being drilled, the industry is focusing more attention on how to use gravel packs to greater effect in long heterogeneous sections. Keys to success are productivity, management of formation damage through optimal filter cake design, and attainment of long term sand control by ensuring complete gravel placement over the entire producing interval.
This case history discusses a high angle open hole gravel pack application for a sand shale sequence. Inhibition of these highly reactive intra reservoir clays was achieved using a low solids formate based mud system. Full gravel placement along the high angle (75°) reservoir section was accomplished using an alternative path gravel pack technique. Filter cake removal, unlike other industry approaches using acids, relied on application of enzymes to enhance the cleanup/back production of filter cake through the oversized gravel and so maximise productivity.
The discussion will focus on the system design approach to drill-in fluid design / clean-up, and the actual gravel pack placement. Finally, the productivity performance, as deduced from pressure transient analysis, will be presented to demonstrate the success of the unique clean-up approach adopted for this operation.
Development of a Novel Fluid-Loss Control Pill for Placement Inside Gravel-Pack Screens
Authors: Luyster M. R. , Foxenberg W. E. , Ali S. A. 
Published: December 2007

Abstract
Controlling fluid losses to the formation, both before and after sand control completions, is critical to optimizing production. While mechanical devices, such as flapper valves, remain the preferred choices for preventing fluid loss when the service tools are removed from the production packer, they sometimes fail or otherwise cannot be used. In those instances, chemical fluid loss control pills are frequently used as supplements or contingencies. Unfortunately, this option normally requires remedial treatment that adds cost and can cause a host of additional problems, not the least of which is the risk of formation damage.
This paper describes the development of a uniquely engineered fluid-loss control pill, designed for placement inside the gravel pack screen and that has been shown to effectively control fluid loss without the subsequent need of remedial treatment. The authors demonstrate that optimizing the particle size distribution of the bridging particles within the fluid loss pill for specific screen types deposits a surface filter cake against the inside surface of the gravel-pack screen assembly. Complementing the development of the fluid loss control pill, which can be pumped at comparatively small volumes, is a proprietary additive specifically designed to reduce the adhesive forces to metal or rock surfaces and which allows complete cake removal, using only production as the flow medium.
The laboratory developmental program and a large-scale screen-flow model designed to simulate pill deposition on various gravel-pack screen types are described. Further, through field experiences, the authors will document the ability of these fluid-loss control pills to produce near zero skin and maximize production without the need for costly and risky remedial removal treatments.
Experimental Approach to Characterize Drilling Mud Invasion, Formation Damage and Cleanup Efficiency in Horizontal Wells with Openhole Completions
Authors: Longeron D. G. , Alfenore J. , Salehi N. , Saintpère S. 
Published: December 2007

Abstract
The increasing number of horizontal wells being drilled, together with the continuing development and use of open hole completions has resulted in increasing reliance on formation damage testing to select the appropriate drilling fluid and/or cleanup technique. A two-year laboratory study was conducted to evaluate i) near wellbore invasion and related damage due to two typical Drill-In fluids (D.I.F.) and ii) performance of various cleanup procedures using specific "breakers".
In the first part of the paper, values of Flow Initiation Pressure (F.I.P.) and return permeability measured on rock samples damaged with an Oil-Based Mud (OBM) and with a Water-Based Mud (WBM) are compared to evaluate the self cleaning properties of sandstone core samples having a large permeability contrast. In the second part, the performance of various "breakers" (mutual solvent, emulsified acid, surfactants for OBM, oxidizers and enzymes for WBM) is presented. Results show that the OBM present better filtration properties and is less damaging than the WBM. The general trend is that near wellbore return permeability (0–10 cm) and self cleaning properties are strongly related to the Jamming Ratio (Mean pore throat diameter/mean mud solids diameter). The use of OBM breakers may induce additional damage if the soaking time is not carefully controlled. On the other hand, WBM breakers may be efficient if they are used under optimum conditions.
Finally, some recommendations are given for designing a low-damaging D.I.F. and to define, if necessary, the best cleanup procedure.
Minimising Clay Sensitivity to Fresh Water Following Brine Influx
Authors: Conway Michael W. , Himes Ron E. , Gray Russell 
Published: December 2007

Abstract
Well productivity or injectivity can be significantly affected by damage to the reservoir section of a well due to reaction between the formation and the introduced fluids. Most reservoirs in the mid-continent region of the United States have varying amounts of illite (and mixed layer illite/smectitie) and kaolinite clays. These non-swelling clays are susceptible to migration thus causing permeability loss due to plugging of pore throats. When abundant amounts of these clays are identified by petrographic techniques, water sensitivity is usually proposed as a potential problem in the reservoir.
Surprisingly, we have found that many reservoir rocks with greater than 10% clay can be perfectly stable to the introduction of fresh water. The cation content of the reservoir brine present at the time of clay diagenesis or the resident formation brine dictates whether or not the clays will be sensitive to fresh water. Many of these reservoirs have low salinity connate fluids of less than 30,000 total dissolved solids. We have identified that previously stable clays can become sensitised to freshwater due to introduction of an intermediate brine such potassium chloride as commonly used in completion operations. Laboratory studies will be presented that identify the factors responsible for permeability stability in rocks containing illite and kaolinite clays.
Interaction Between Growing Channels in Proppant Packs: Length and Number of Channels
Authors: James Simon G. , Lee Chengho , Howard Paul R. , Cundall Peter A. 
Published: December 2007

Abstract
The formation of channels in propped fractures, in the presence of fibers, has been demonstrated experimentally under a wide variety of conditions. The presence of channels can have a significant impact on the effective fracture conductivity and consequently the productivity of a given well. While single channels are observed in experiments, a question is how many channels may be present in real proppant packs and how long do they grow? The length is especially important when proppant flowback control additives are used as "tail-ins" with the last part of the proppant pack. To complement the experimental study, the understanding of channel propagation and the interaction between multiple growing channels was modeled using finite difference codes.
Modeling was performed using a 2-dimensional explicit finite difference program. The formation of channels was predicted by using two parameters – a critical flow rate and a curvature limit. Results demonstrated that the curvature limit is a critical parameter in determining the stability of channels. Calibration of the model with laboratory experiments with proppant and fibers provided clear explanation as to why channel formation provides proppant pack stability at high flow rates.
For a given flow rate, channels grew until a stable length was attained; increasing the flow rate would cause the channel to grow further until a subsequent stable length was attained. Multiple channels were generated but a dominant channel grew once the length of the channel was greater than the spacing between channels. The presence of one, or several widely spaced, long channels will have a much larger impact on productivity than many short channels. Bilinear flow conditions resulted in channel growth to a stable equilibrium length. This is expected to occur in real fractures. A consequence of this behavior is that fractures should be flowed back at high rates to grow channels that will then be stable at subsequent production rates.
Fluid Leakoff and Net Pressure Behavior of Frac&Pack in High-Permeability Viscous Oil Reservoirs of the Duri Field, Indonesia
Authors: Fan Y. , White D. E. , Aimar A. , Satyagraha M. T. 
Published: December 2007

Abstract
Frac&pack has become a preferred completion method for the Duri field in Indonesia, where the reservoir is shallow, highly permeable and unconsolidated containing heavy viscous crude. This paper presents simulation of fluid leakoff and net pressure behavior for the frac&pack treatments in the Duri field. Several issues concerning selection of fracturing fluids and proppant, fracture dimensions and treatment designs are also discussed in the paper.
A pressure-dependent leakoff model that is based on a transient flow of a polymer solution displacing a reservoir fluid is presented and coupled with a fracture mechanics model to investigate the interactions among the leakoff, net pressure and created fracture dimensions during different stages of frac&pack treatments. The results indicate that the leakoff is controlled by reservoir fluid viscosity and is dependent upon the rock-mechanics properties and the mobility ratio between the invaded solution and the reservoir fluid. In the absence of filtercake, the traditional leakoff notion using the concept of a constant leakoff coefficient fails to capture the transient behavior of polymer invasion and reservoir fluid compression. Because of high sensitivity to leakoff and the rock-mechanics properties, the net pressure behavior is also quite different from the one anticipated. For the typical formation with an elastic modulus of 50,000 to 100,000 psi in the Duri field, the net pressure is in a range of 20–40 psi during fracture propagation. The simulation also indicates that the net pressure over 200 psi would result in desirable fracture widths for Duri field applications.
Zonal Isolation in Stimulation Treatments and Gas/Water Shutoff Using Thermally Compensated Inflatable Packers and Plugs
Authors: Wilson Paul , Hoffman Corey E. 
Published: December 2007

Abstract
This paper provides laboratory and field-test results of a thermally compensated fluid-inflated packer system. This system greatly reduces the chance of sealing-element failure when inflatable packers or plugs are used where the borehole fluid changes temperature more than 50° F (10°C). To date, a primary cause of failure in achieving zonal isolation while using inflatable packers and plugs is the change in temperature of the borehole and inflation fluids once the packer is set.
Thermally compensated inflatable packers are an innovation in inflatable packer technology. These packers act in a manner unlike conventional inflatables, which are susceptible to temperature changes as little as 50° F (10°C) between borehole and internal fluids. These temperature changes can cause the fluids inside conventional inflatable packers either to expand and rupture the element or to contract and cause the element to lose its seal on the casing wall. Qualification tests and resulting data will be presented as well as data acquired after a thermally compensated inflatable plug system was deployed in a water injection well.
Possible applications include those in which a fluid inflatable packer, straddle packer, or plug would be used and subjected to temperature changes in excess of 50° F (10°C).
The introduction of thermally compensated inflatable packers offers a more technically effective, economical means of zonal isolation in almost any cased-hole application. This technology is equally applicable for openhole applications.
Improved Hole Cleaning and Reduced Rotary Torque by New External Profile on Drilling Equipment
Authors: Boulet J. G. , Shepherd J. A. , Batham J. , Elliott L. R. 
Published: December 2007

Abstract
This paper will describe the successful application and effects of completely new Hydromechanical Cleaning and Hydrodynamic Bearing profiles machined externally on drilling equipment to improve hole cleaning and reduce rotary friction. Qualification programmes, including initial proving trials on a test rig, computational fluid dynamics and cuttings transportation flow loop tests, will supplement details from successful field operational use of this equipment.
20-Plus Years of Tuscaloosa Drilling: Continuously Optimizing Deep HTHP Wells
Authors: Shaughnessy J. M. , Locke H. A. 
Published: December 2007

Abstract
Drilling the Tuscaloosa formation in Louisiana was as challenging as any area drillers worked 20 years ago. It was one of the most active areas in the U.S. Problems that were new at the time such as gas solubility in oil base mud, sulfide stress cracking of tubulars, pressure regressions and low margins between the fracture pressure and pore pressures resulted in numerous well control problems and high cost wells. Activity decreased in the mid 80's when the gas price did not encourage operators to challenge the drilling risks. BP Amoco is still successfully drilling to 22,000' into to 16,000 psi, 380°F reservoirs that are now depleted over 10,000 psi.
This paper will address steps taken to optimize the drilling operation and continue making the wells economical. First, drilling problems such as stuck pipe, lost returns, drill string failures and well control had to be minimized. Next, successful cement jobs were required and have resulted in the highest rate completions in the history of the Trend. All objectives had to be achieved in a safe manner with little impact on the environment.
Application of Novel Downhole Hydraulics Software to Drill Safely and Economically a North Sea High-Temperature/High-Pressure Exploration Well
Authors: Thorsrud A. K. , Ekeli Ø. , Hilbig N. C. C. , Bergsvik O. , Zamora M. 
Published: December 2007

Abstract
Understanding and predicting the downhole hydraulics behavior of a drilling fluid are important for successful drilling and avoiding wellbore instability, well-control situations, and lost circulation. This is especially critical in a drilling environment where invert emulsion drilling fluids are exposed to high temperatures and pressures, and the operating window between pore-pressure and fracture gradient is narrow.
A North Sea well drilled under HTHP conditions (350°F, 14,000 psi) realized the time and financial benefits of a wellsite concept involving a hydraulics engineer and a fit-for-purpose software program for accurately predicting downhole pressures while drilling and tripping. Downhole equivalent static densities up to 18.0 lb/gal were required with a fracture gradient of only 18.5 lb/gal. ECDs were carefully monitored and tripping speeds were optimized based on software pressure predictions. Computer simulation was particularly valuable, and even necessary, when downhole temperatures exceeded the thermal limit for the pressure-while-drilling tool.
Accurate prediction of downhole pressures while drilling and tripping reduced well observation time while avoiding well-control and lost-circulation incidents. Subsequent implementation of this technology in a nearby field contributed to estimated cost savings of US$ 3,000,000.
To the Limit and Beyond - The Secret of World-Class Extended-Reach Drilling Performance at Wytch Farm
Authors: Meader Tony , Allen Frank , Riley Graham 
Published: December 2007

Abstract
The paper describes how the extended reach drilling team at BP Amoco's Wytch Farm development on the South Coast of England met the challenge of drilling and completing technically advanced ERD wells in an increasingly difficult cost and performance focused environment. The key element in this success was the ability to continue developing new technology, while at the same time adopting a technical limit approach to performance delivery. Focusing attention on the individual components that make up a well allowed the team to build on the reliability and experience of using rapidly maturing technologies. It also gave the team confidence in the management of the risks associated with the application of new technologies and more importantly allowed the team to fight back and recover from events that would ordinarily provide justification for well programme timings and costs to slip.
The paper will draw on the experience of three wells drilled from August 1998 to August 1999. M-14 a 9,600m water injection well; M-15 a multilateral well with one lateral drilled to 8,900m and the second to 6,700m;
and M-16 a record breaking ERD well drilled to 11,278m.
The techniques and technologies discussed will be; building a highly motivated team that can manage risk, perform consistently and perform safely; rotary steerable systems; torque and drag simulation and control; casing and liner floating techniques; ECD and mud loss control; multilateral junctions at high angles and downhole flow control completions.
In conclusion the paper shows how powerful a team can be in delivering significant performance improvements even towards the end of a 6 year 17 well development.