bluuebunny/crossref_metadata_2025_split huggingface dataset:
PDC cutter and Bit development for challenging Conglomerate Drilling in the Luno Field - Offshore Norway
Authors: Hellvik Svein , Nygaard Runar , Hoel Espen , Andersen Mats , Francis Mark 
Published: June 2014

Abstract
The Luno discovery in the Norwegian sector of the Southern North Sea, with an estimated 180 million recoverable barrels of oil (Greater Luno area including Tellus) in a conglomerate and sandstone reservoir, has proven to create unique drilling challenges. The reservoir, planned with horizontal or 60° slanted producers and inclined water injectors, consists of both sandstones and conglomerates with granite clasts of varying sizes.
During the exploratory phase the conglomerate was mainly cored with diamond impregnated bits. The recorded rate of penetration (ROP) through the conglomerate spanned from 0.5- to 3.5-m/hr; for most of the time it stayed at between 1- and 2-m/hr. Reduced well cost was one of the early identified major potential field development savings if the conglomerate can be drilled with polycrystalline diamond compact (PDC) bits capable of an ROP of 10- to 15-m/hr, and which would last for 500- to 1000-meters reservoir sections.
To investigate the feasibility of using PDC bits, after reaching the target in appraisal well 16/1-13, the well was deepened utilizing two different types of PDC test bits. After the PDC field tests were conducted with the first bit ringed out after 70 meters and the second bit partially worn out after 34 meters of rough drilling, it was decided to initiate a PDC development project to develop a PDC bit with cutters that could withstand the challenging drilling of the conglomerate for the upcoming field development/production phase. A "conglomerate pie" test block was manufactured and used in a vertical turret lathe to conduct single cutter PDC testing. Utilizing the improved wear and impact resistance of the new enhanced cutters developed based on results from the testing, an experimental bit with different cutter types was used in another well with hard basement rock. From the cutter and bit performance observed during the field test, further laboratory- and field testing was conducted with these cutters showing preliminary performance results of 3- to 4-times initial durability potential for a constant ROP.
Sand Consolidation in the Mahakam Delta: 3 Years Later
Authors: Chaloupka V. , Descapria R. , Mahardhini A. , Coulon D. , Tran Q. , Haekal M. , Santoso D. C. , Amar A. , Nusyirwan A. 
Published: June 2014

Abstract
Tunu and Tambora gas fields are located in the Mahakam river delta in the province of East Kalimantan, Indonesia. The fields consist of wet gas bearing sand bodies over a height of 13000 ft. Most of the wells are multizone gas producers completed with cemented tubing without primary sand control, and are produced with a bottom-up perforation strategy. The main objective is gas production from the deeper Main Zone layers. The shallower reservoirs prone to sand production were not targeted until recent years. With progressing depletion of deep reservoirs in the Main Zone and bottom up perforation strategy the operator started perforating upper zones. This resulted in an increasing number of interventions or shutting wells in due to sand production.
Due to this fact the operator started considering remedial sand consolidation about 5 years ago. The first successful trials using internally catalysed epoxy resin fluid were prepared in late 2008 and results presented at the 2010 SPE International Symposium and Exhibition on Formation Damage Control (Chaloupka et al. 2010). Initially, these consolidation treatments aimed to find a remedial solution for existing wells choked back or shut in due to sand production. These successful trials, however, quickly turned the project into using consolidation essentially as a primary sand control method.
First treatments targeted weakly consolidated sands in both Tunu and Tambora fields (5,000 to 8,000 ftTVD) using high temperature internally catalysed epoxy consolidation fluid. The treatments showed encouraging results and confirmed this as a viable option for sand control.
In 2010 with growing confidence in the method the operator considered performing sand consolidation in very shallow fully unconsolidated Tunu Shallow zones (2,300 to 5,000 ftTVD) as an alternative to standard single trip multi-zone gravel packs which are conventionally pumped in Tunu Shallow. Five treatments have been performed using a low temperature version of the consolidation fluid with encouraging results. The preliminary performance envelope validated from the treatment is 3 MMscfd of gas per meter perforated or a drawdown of 300 psi.
The paper aims to describe the experience from the initial trials to field application including placement and fluid QAQC procedures as well as treatment results. The failures and difficulties that have been encountered are looked at in more details.
Vibration Analysis in Riserless Conditions
Authors: Samuel Robello 
Published: June 2014

Abstract
Riserless drilling poses numerous operational challenges that adversely affect the efficiency of the drilling process. These challenges include increased torque and drag, buckling, increased vibration, poor hole cleaning, tubular failures, poor cement jobs, and associated problems during tripping operations. These challenges are closely associated with complex bottomhole assemblies (BHAs) and the vibration of the drillstring when the topholes are drilled directionally. Current methods lack proper modeling to predict drillstring vibration.
This paper presents and validates a modified model to predict severe damaging vibrations, analysis techniques, and guidelines to avoid the vibration damage to BHAs and their associated downhole tools in the riserless highly-deviated wells. The dynamic analysis model is based on forced frequency response (FFR) to solve for resonant frequencies. In addition, a mathematical formulation includes viscous, axial, torsional, and structural damping mechanisms. With careful consideration of input parameters and judicious analysis of the results, the author demonstrates that drillstring vibration can be avoided by determining the 3-D vibrational response at selected excitations that are likely to cause them. The analysis also provides an estimate of relative bending stresses, shear forces, and lateral displacements for the assembly used. Based on the study, severe vibrations causing potentially damaging operating conditions were avoided, which posed a major problem in the nearby wells.
The study indicates that the results are influenced by various parameters, including depth of the mud line, offset of the wellhead from the rig center, wellbore inclination, curvature, wellbore torsion, and angle of entry into the wellhead. This study compares simulated predictions with actual well data and describes the applicability of the model. Simple guidelines are provided to estimate the operating range of the drilling parameter to mitigate and avoid downhole tool failures.
Hammer Motor Smashes Its Way to Speedy Success in Brazil
Authors: Gee Ryan , Ramirez Tibor , Barton Steve , de Souza Julio Cezar , da Fonseca Carlos Eduardo , Cote Brad , Valmorbida Decio 
Published: June 2014

Abstract
Percussive air hammer tools have been used for many years to increase drilling ROP (rate of penentration) in air drilling applications. Similar developments for mud hammer tools have not been as successful. The incompressible nature of drilling mud makes the percussive action much slower to actuate using the same design methodology, rendering the tool ineffective. Other developments have suffered from reliability issues which have limited their drilling hours, therefore making them economically unfeasible.
A novel percussive mechanically-actuated Hammer Motor, suitable for either mud or air drilling applications, has changed the landscape. This unique hammer assembly is assembled into a standard mud motor, without affecting the bit to bend distance. The percussive action of the tool is designed such that the bit remains in contact with the formation, while the hammering takes place against the top of the drive mandrel, driving the bit into the formation. The percussive impacts serve to greatly increase the effectiveness of the roller cone bit in crushing the rock, thus significantly increasing ROP.
This paper illustrates a case study from Brazil, where the Operator has been using turbine motors or conventional motors to drill vertical wells through hard rock formations. The Hammer Motor displayed significantly higher ROP than the benchmark established by the other motors, while also reducing bit costs. These improvements in drilling performance improve the economics of drilling these hard rock formations, and are also applicable to other drilling applications.
Wormhole Propagation in Tar During Matrix Acidizing of Carbonate Formation
Authors: Al-Mutairi S. H. , Al-Obied M. A. , Al-Yami I. S. , Shebatalhamd A. M. , Al-Shehri D. A. 
Published: June 2014

Abstract
Heavy, viscous oil deposits and tar have low °API gravities and occur as part of several oil formations. Unlike normal oil deposits, heavy oil and tar tend to contain more inorganic impurities and to be more sulfurous and aromatic. And as so, they tend to have different responses to acidizing fluids during matrix acidizing treatments. One fundamentally interesting phenomenon is the wormholing characteristics ofacidizing tar formation. This paper discusses the effect of acid and its wormholing characteristic on tar and on carbonate rock that was saturated with crudes that have varying °API gravities.
Experiments included acid flooding of core plugs that were saturated with different °API gravities. The extreme case included flooding the acid through tarsaturated plugs. The wormholes were characterized by CT Scanning. Differential pressures, number and sizes of wormholes and breakthrough volumes were all measured for each experiment. The tests involved regular hydrochloric acid and emulsified acids.
This study showed that regular and emulsified acids produced comparable wormhole penetration in tar. Tar formations were difficult to exhibit face dissolution even at extremely low injection rates. In general, it was noticed that penetration and, hence, benefit from emulsified acid is reduced when higher °API oil saturated the rock. The wormhole breakthrough volume in a rock saturated with intermediate oil was less than that of a rock saturated with condensate oil. Condensate might have allowed better diffusion of acid droplets to react with the rock.
This work provided a fundamental investigation that can lead to development in producing these challenging prospects. In addition, these results are of special interest when long horizontal injectors or producers are placed within the tar zone of conventional oil reservoirs.
Solving Multiple Carbonate Challenges: TCI Delivers Performance Step-Change Drilling Deep 28-in Hole Section
Authors: Al Saeedi Mohammed J. , Al Fayez Fayez , Sounderrajan Mahesh , Al Mudhaf Mishary N. , Portwood Gary R. , Ghoneim Osama , Maliekkal Harish 
Published: June 2014

AbstractIt is well documented carbonate formations cause a multitude of drilling problems. Because the majority of reservoirs in Kuwait are carbonates, the operator is consistently searching for technology to improve drilling efficiency. To reach the hard Jurassic carbonate reservoir, the operator must drill through a series of demanding Tertiary and Cretaceous formations. The fractured Dammam and Tayarat formations are notorious thief zones and can aggravate drilling problems.The strategy to get maximum hole size to the deep HPHT Jurassic reservoir starts by constructing a 28" borehole through Dammam to TD in Mutriba. The section is interbedded with anhydrite/shale and has compressive strengths between 4- 30Kpsi. At TD, 24" casing is run to isolate the problematic formations. The hole section is approximately 5000ft long but varies depending on the field. These interbedded formations and thief zones create a major challenge for rollercone bits including, impact damage from hard stringers, high WOB and on-bottom time in excess of 250 hours can reduce average ROP to an unacceptable level. Additionally, heat-induced bearing stress caused by low circulation rate in loss-prone formations adds to the applications complexity.To solve the challenge, the drilling team produced an optimized 28" TCI rollercone bit with custom insert geometry and updated carbide grades to increase cutting structure longevity. Over the last several years the new-style bit, along with optimized operating parameters has consistently drilled the entire section in one run and set a multitude of new footage and ROP records. The authors will discuss the application challenges and TCI bit development. They will present an in-depth engineering analysis that documents footage increases and several new ROP benchmarks in Kuwait. The improved performance has resulted in an average per application cost savings of 3.5 rig days/$175,000 for the operator.
Modeling of Square Mesh Screens in Slurry Test Conditions for Standalone Screen Applications
Authors: Chanpura R. A. , Mondal S. , Andrews J. S. , Mathisen A. , Ayoub J. A. , Parlar M. , Sharma M. M. 
Published: June 2014

Abstract
There are two types of sand retention tests generally used in the industry to evaluate the performance of sand control screens for standalone screen applications: pre-pack tests and slurry tests. They represent complete hole collapse and gradual rock failure around the wellbore, respectively.
In this paper, we present analytical results as well as Monte Carlo simulations to estimate sand production in slurry type sand retention tests with square mesh screens taking into account the full particle size distribution of the formation sand. We also compare the model results with experimental data and demonstrate that this approach can be used to predict sand production for different sand size distribution/screen size combinations without the need for physical tests. This work augments previously published slurry test models that were limited to wire-wrap screens, and enables comparison of the performance of square mesh screens to wire-wrap screens.
The analytical model along with Monte Carlo simulations provide a direct and reliable way to estimate the amount of sand that will be produced for a given sand size distribution and a given screen size. Since the proposed methods are much more quantitative, they represent a significant improvement over current methods that rely on single design points or rules of thumb for screen selection.
Low Extrusion Pressure Polymer Gel for Water Shutoff in Narrow Aperture Fractures in Tight and Shale Gas and Oil Reservoirs
Authors: Gakhar K. , Lane R. H. 
Published: June 2014

Abstract
Excess water production can lead to premature operating cost escalation or well abandonment in conventional oil and gas reservoirs. This can also happen in tight and source rock production in cases where hydraulic fractures connect the stimulated well to a water source, especially with low hydrocarbon production rates. Polymer gel technology has been successfully used in controlling water influx with no or minimal damage to hydrocarbon production in conventional naturally fractured or hydraulically fractured reservoirs. However, there has been no public description of polymer gels tailored for shutting off water flow from fractures with the very narrow apertures expected in tight and source rock reservoirs.
Established water shutoff polymer gels like those based on hydrolyzed polyacrylamide (HPAM) crosslinked with chromium(III) acetate will exhibit high extrusion pressure while penetrating the expected narrow aperture fractures present in source rock and tight gas reservoirs. This is likely to cause significant limitations to their application in unconventional resources, thus giving rise to this study on development of a polymer gel system that can be used for shutting off water flow from narrow aperture fractures. In addition to improved placement rheology, an improved gel system should ideally be composed of components that are less of an environmental concern than metal ion-crosslinked systems.
This report focuses on developing a low viscosity, environmentally benign polymer gel system based on high molecular weight (HPAM), as the polymer component and a commercial grade polyamine containing polyethyleneimine (PEI) as an organic crosslinker. Gelant and gel samples of different concentration ratios of polymer and crosslinker were prepared, subjected to rheological measurements and classified using a semi-quantitative gel strength coding to find optimum concentration ratios that gave good gels. Results indicate that the HPAM/PEI system can provide a gelant with lower initial viscosity, higher final gel strength and potential greater stability at higher temperatures than current metal ion crosslinked gel systems.
Waterless Cement Slurry Controls Water Production in Southern Mexico Naturally Fractured Oil Wells
Authors: Sourget A. , Milne A. , Diaz. L. , Lian E. , Larios. H. , Flores P. , Macip M. 
Published: June 2014

Abstract
Water control is one of the greatest challenges in Southern Mexico wells, where the reservoirs are generally fractured carbonates. Many of the wells have early water breakthrough as a result of one or more of the following: water coning, near- wellbore flow, high-conductivity channels, high-conductivity layer breakthrough, segregated layering, and inadequate completions.
In cases where it is possible to shut off the producing interval and recomplete the well in a new interval, reticulated polymer gels and/or cement slurries can control water production. However, when the water is produced in a different interval than the oil, the success rate of reducing the water cut is less than 30%.
In these cases, waterless cement slurry squeezes have proven to be an effective solution to unwanted water production. This method has been used to successfully reduce water cut in several fields in South Mexico with a nearly 100% success rate.
A well which was carefully evaluated as a candidate and then treated with a waterless cement slurry resulted in a reduction in water cut from 71% to 5%, while oil production increased from 290 barrels of oil per day (BOPD) to 1054 BOPD. In addition, the deferred production was greatly reduced using this technique—less than four days compared with several weeks using alternative techniques.
Water cement squeezes are a cost-effective way to reduce water production in the producing intervals of naturally fractured reservoirs. This technique has increased oil production while resulting in significant cost savings in terms of both treatment costs and deferred production.
The Influence of Fluid Loss Additives in High-Temperature Reservoirs
Authors: Watson R. B. , Viste P. , Lauritzen J. R. 
Published: June 2014

Abstract
Reservoir drilling and completion fluids are affected by temperature. Fluids that perform well at one temperature range can experience major problems at higher temperature ranges. A series of studies have been conducted over the last four years looking in detail at the effect of reservoir drilling fluid design for high-temperature, high-pressure (HTHP) reservoirs, with significant developments in the understanding of the role of fluid loss additives. The focus of these studies was to reduce and control formation damage, in addition to allowing efficient drilling and effective logging of exploration wells. This paper reviews and explains the findings of these investigations and the significance on past and future reservoir exploration and drilling operations.
The studies were all required to assist in a number of specific drilling campaigns where logging of reservoir pressures was planned or had been performed and was believed to be influenced by formation damage. The investigations were initiated with sufficient time to allow hundreds of formulations to be tested with regards to drilling properties, stability and formation damage.
Very distinctive improvements in HTHP return permeability and filter cake thickness were obtained, which was accompanied by logging success. The most notable controlling factor of return permeability under HTHP conditions was determined to be the fluid loss additive. The selection and quantity of fluid loss additive was so significant that it alone could vary the return permeability by more than 80%.
The findings from these investigations have been put to practical use in a number of exploration wells where pressure measurements have been taken with great success. One notable investigation focused on a formulation used 10 years ago on a reservoir where pressure measurements could not be taken. The reservoir was abandoned until recently due to the apparent lack of pressure. This paper details the problems encountered and the results of the investigation in addition to the techniques used to prevent similar problems occurring again.
New and Effective Filter Cake Removal Optimizes Water Injectivity
Authors: Davidson E. , Mota L. , Mosley N. , Chimara G. , Morrison A. , Archibald I. 
Published: June 2014

Abstract
The Captain Field which lies off the coast of Scotland is a shallow sandstone reservoir (3000 ft) comprising clean, unconsolidated sand with high permeability (up to 5D). The oil is heavy and bottomhole temperature very low (30o C). Throughout the development of this field (14 years) two of the main challenges have been control of unconsolidated sand and maximising production of the oil by water injection to maintain reservoir pressure.
Particular attention has been paid to drilling and completion of the water injection wells. The drill-in fluid used was initially oil based mud but changing to water based drill-in fluid facilitated use of faster completion procedures. Initially, when using a water based drill-in fluid, displacement of the openhole to clear brine was always troublesome. This issue was resolved by the introduction of a new low temperature starch into the drilling operation. Adoption of the new formulation has facilitated a simpler, faster displacement operation and made it easier to test various techniques that are offered for filtercake clean up. Treatments, involving acetic acid released in situ, enzymes, sequestering agents, etc., provided questionable results. However, a breaker system that provides a delayed release of formic acid has recently been introduced and has led to a significant improvement in performance.
New techniques have introduced significant benefits, for example: the improved starch shortened the completion process by at least several hours of rig time,the four most recently completed wells which were all treated with the formic acid system had an average initial Specific Injectivity Index that was about 50% better than the average achieved for the first five wells that were completed with oil based mud.
The paper will present important aspects of the learning process on the Captain Field with particular emphasis on application of the new starch, and drilling/clean-up of the water injection wells.