bluuebunny/crossref_metadata_2025 huggingface dataset:
Challenges of Directional Drilling Through Salt in Deepwater Gulf of Mexico
Authors: Israel R. R. , D'Ambrosio P. , Leavitt A. D. , Shaughnessey J. M. , Sanclemente J.
Published: March 2008

As an increasing number of 6000-ft plus deepwater developments come on stream in the Gulf of Mexico (GoM), project economics dictate that fewer subsurface drill centers be used to develop these fields. This in turn requires longer step-out wells, pushing kickoff points higher up the wellbore, often occurring within extensive salt bodies. Salt drilling is still a relatively new practice and presents operators with many drilling challenges that are still not totally understood. Adding a directional component to drilling through salt not only magnifies the issues of traditional salt drilling, but introduces new challenges that require different approaches to ensure successful delivery. This paper will discuss the challenges faced and the lessons learned by two major deepwater GoM operators along with the directional service company in drilling directionally through the salt. Together, these companies have drilled over 100,000-ft of salt in the GoM and are considered pioneers in deepwater salt drilling. They have encountered and managed many of the challenges that extend past the traditional predrill and real-time directional issues, into the post drilling phase with issues such as casing and cement design for managing salt loading and ensuring long term wellbore viability.

This paper presents several case studies that investigate and discuss directional drilling through salt, comparing variables such as hole size, bottomhole assembly (BHA) configuration, under-reamer selection, wellbore trajectory and directional control. The importance of geomechanics in the predrill planning of these directional salt wells is also discussed, and its link to casing design and cementing issues will be examined. The paper concludes by identifying critical areas for success in drilling directionally through salt, and will attempt to identify current technical drilling limits for pushing this envelope even further.
Concurrent Rotary-Steerable Directional Drilling and Hole Enlargement Applied Successfully: Case Studies in North Sea, Mediterranean Sea, and Nile Delta
Authors: Jones Steve , Sugiura Junichi
Published: March 2008

Concurrent rotary-steerable directional drilling and hole enlargement utilizing concentric underreamers is becoming more commonplace. Significant cost savings can be obtained enlarging the hole while drilling with a rotary-steerable system (RSS) as opposed to using a designated hole-opener run after the pilot has been drilled. However, RSS underreamer assemblies are often challenged with BHA instability, excessive vibration and stick-slip problems when the two different cutting structures (bit and underreamer) interact with significantly different formations.

This paper describes case histories of directional wells that have been drilled with both point-the-bit and push-the-bit RSS underreamer assemblies in the North Sea, Mediterranean Sea and Nile Delta (Egypt). In particular, RSS underreamer assemblies opening from 13″ to as large as 17 ½", using 12 ¼" pilot holes will be discussed.

A unique sensor system, integrated into this specific RSS provides measurements of near-bit borehole caliper, stick-slip and vibration. While drilling, borehole quality and downhole vibrations were monitored in real-time at the rig site and from a remote operating center. The real-time data was used to optimize drilling parameters and provide enhanced performance from the RSS underreamer assembly. The RSS solution to simultaneous wellbore enlargement has been analyzed in terms of vibration, efficiency, performance, directional objectives and cost.

The physical components, operational aspects and limitations of RSS underreamer technology will be discussed. The combination of a specific RSS and underreamer with a balanced cutting structure has resulted in excellent ROP and directional control, while reducing reaming-related vibration and potential failures. Further, an automated directional drilling feature and real-time drilling process monitor have enabled optimum directional drilling performance.
What Really Happens to High Strength Drillpipe When Taking a Sour-Gas Kick?
Authors: Spoerker H. F. , Havlik W. , Jellison M. J.
Published: March 2008

Sour gas and high-strength steel are generally accepted to be incompatible. However when drilling beyond 20000ft S135 and higher steel grades become necessary to support their own weight, and due to the elevated down hole pressures in the range of 15–20ksi, even minimal concentrations of H2S result in partial pressures that are considered hostile for these steel grades. The paper presents initial results from a joint industry project exposing S-grade drill pipe samples to various H2S concentrations in temperature ranges from 70–170°C and exposure times of 1–3 hours, representing typical conditions when circulating a gas kick to surface. Test conditions have been designed to closely recreate actual down hole conditions, with actual potassium carbonate drilling fluids saturated with hydrogen sulphide and an additional free gas phase. After exposure to the sour environment, the samples have then been taken to fatigue testing to evaluate actual damage against undamaged base-line fatigue results.
A New Mud Pulse Telemetry System for Enhanced MWD/LWD Applications
Authors: Klotz C. , Bond P. , Wasserman I. , Priegnitz S.
Published: March 2008

Mud Pulse Telemetry systems in drilling operations have enabled the industry to gather valuable directional and formation data while drilling the well, and to optimize the drilling process. This makes drilling operations more cost efficient and allows the drilling of complex wells.

In recent years, new LWD technologies have dramatically increased the amount of information collected downhole. This increasing demand for realtime bandwidth is a major challenge for conventional Mud Pulse Telemetry, which has data rates that are normally below 3 bits per second.

This paper describes a system for downhole-to-surface Mud Pulse Telemetry that uses baseband or carrier modulated pressure signals generated by a novel mud pulser design and a surface data acquisition unit with advanced signal processing capabilities. The new system is able of handling the complex and continuously varying properties of the transmission channel (the pipe bore filled with flowing drilling mud) by optimizing the transmission signal and the surface processing algorithms in realtime. Under a given scenario, higher data rates can be achieved that, from a log-quality standpoint, result in high log-densities for improved realtime decision making.

Surface processing algorithms include active pump noise cancellation, dual pressure transducer processing, signal filtering and signal decoding.

In addition, the system contains an automated calibration routine that after turning pumps-on measures the characteristics of the transmission channel. This novel feature assures that the latest knowledge about the transmission channel is available in the processing algorithms.

The new system has been successfully run in field-trials in the United States, North Sea, South America and the Middle East. During these deployments, data rates could be substantially increased compared to previous offset runs. The focus in this paper will be on a description of the system and its impact on both MWD and LWD realtime services.
Automatic Measurement of Drilling Fluid and Drill Cuttings Properties
Authors: Saasen A. , Omland T. H. , Ekrene S. , Breviere J. , Villard E. , Kaageson-Loe N. , Tehrani A. , Cameron J. , Freeman M. , Growcock F. , Patrick A. , Stock T. , Jørgensen T. , Reinholt F. , Scholz N. , Amundsen H. E. F. , Steele A. , Meeten G.
Published: March 2008

In order to remotely control the drilling process it is necessary to measure several drilling fluid parameters automatically. This will increase objectivity of the measurements as well as make it possible to immediately react to changes. The current paper describes in detail the design for an integrated tool combination and the results of a full size yard test of such a combined set of tools for measuring drilling fluid parameters and formation properties automatically. Some of the automated tools have been tested on rig site operations. Results from these individual tests are also presented.

The automatic drilling fluid analysis includes viscosity, fluid loss, electric stability measurements and chemical properties like pH. Full viscosity curves for the drilling fluid are measured using configurations and shear rates similar to those suggested by API procedures. Since gel formation curves and fluid loss properties require some sort of controlled static periods, these measurements are made semi-continuous. However, they are automatic and are measured as frequently as possible.

An automatic system is included to measure the particle size distribution, concentration and morphology. Knowledge of these parameters is necessary, especially when drilling in depleted reservoirs where particles are added for increasing the wellbore strength.

The produced cuttings volume is measured. An automatic system is adapted that determines, with accuracy comparable to that of visual analysis, whether the particles separated at the shaker screens are drill cuttings or cavings produced by an unstable formation. The mineralogy of the cuttings is analysed automatically using Raman spectroscopy, making it possible to evaluate continuously the different formations being drilled.
The Utilization of the Massive Amount of Real-Time Data Acquired in Wired Drillpipe Operations
Authors: Olberg Tor Stein , Laastad Harald , Lesso Bill , Newton Adrian
Published: March 2008

Drilling data telemetry rates with the current commercial mud pulse MWD systems present a severe bottleneck to the users of downhole drilling data. Wired drillpipe (WDP) telemetry allows for a several orders of magnitude increase in data transmission rates. StatoilHydro tested WDP during the drilling of the horizontal section of a well on the Visund platform in the Norwegian North Sea. There were two aspects of this test: first, the hardware and process operation of the wired drill pipe with a full range of MWD and LWD tools, and second, the use of this data by a multi-disciplinary team in real-time to turn data into information so that better drilling decisions could be made. While this paper discusses both of these areas, it concentrates on the use of WDP data.

High bandwidth downhole formation evaluation, wellbore, and drilling mechanics data from WDP telemetry were combined with standard surface drilling and depth data for transmission from the platform to an onshore support center. The WDP Enhanced Decision Team was deployed in a passive test mode adjacent to the center. The members of this team had expertise in geomechanics, petrophysics, geology, image interpretation, structural modeling, and drilling mechanics. The nature of the test was that the group could not directly make decisions, but could make recommendations to the Visund operations team who remained the sole authority responsible for the well.

Several value cases were identified during the test, most of which were used in the drilling decision process. These could be broadly categorized into HSE, improved drilling operations, well placement/geosteering, and data transmission. The most obvious and immediate benefit of WDP technology was identified in the areas of fast downlinks and control of downhole tools. High-frequency, time-based data was also useful for real-time torque and drag analysis and borehole quality using real-time caliper data. Better monitoring of downhole formation and wellbore pressures provided a basis for improved well control and borehole stability. The ability to send significantly more curves with higher resolution enhanced the well placement/geosteering process, and may, in the end, represent an even more significant value potential for this technology. Future WDP wells may easily implement these technologies.
Successful Development Drilling of an HP/HT Infill Well in a Highly Depleted Reservoir: Case Study
Authors: Fambon L. , Joffroy G.
Published: March 2008

Drilling infill wells on HP/HT fields after a significant depletion has occurred represents a real challenge. It requires drilling from a cap rock remaining at or close to virgin pressure into a reservoir in which pore and fracture pressures have largely decreased due to production. No mud-weight-window exists anymore at the transition between cap rock and reservoir. The difficulty is further increased by uncertainties in the pressure profile along the well path, the rock mechanics and their change generated by the high and rapid depletion, and also by depth uncertainty on the top reservoir.

For this reason, most HP/HT fields are developed by drilling all wells before a pre-defined limit of depletion level is reached at which the mud-weight-window closes. This limit is usually low.

However, HP/HT producer wells face depletion related threats to their integrity: sand production and / or deformation of the production liner under rock movement. When these threats become effective, the well and its associated production will be lost. Replacement wells will need to be drilled. Additional wells are also needed to increase reserves by creating new off-take points.

This paper describes the preparation work performed before drilling an HP/HT infill well in the highly depleted Franklin reservoir in the UKCS, the management of uncertainties during the drilling and some of the lessons learned from this first experience. Among them is the important influence of the reservoir depletion on the mechanics of the formations above reservoir.

The success of this first HP/HT infill well after significant depletion proves the feasibility of drilling such wells. It opens the door to new opportunities in HP/HT developments.
Innovative Hydraulic Isolation Material Preserves Well Integrity
Authors: Roth J. , Reeves C. , Johnson C. R. , De Bruijn G. , Bellabarba M. , Roy-Delage S. Le , Bulte-Loyer H.
Published: March 2008

Annular fluid or gas migration, resulting in surface hydrocarbon leaks or sustained casing pressure (SCP), is a problem operators face worldwide. With energy demands escalating, it becomes increasingly important to maintain production from existing wells and bring new wells on line without delay. Internal company policies regarding health, safety and environment, along with increased government scrutiny of the petroleum industry, can require wells to be shut-in if leaks or SCP are present.

Estimates of the number of leaking wells have varied widely as reporting standards have evolved over time and from country-to-country. In Western Canada, however, there are detailed reports of over 18,000 wells having Surface Casing Vent Flow (SCVF) that in some cases requires them to be shut in and production suspended.

From spud-in to abandonment, an oil well is subjected to numerous, repeated events that could compromise zonal isolation. Resulting damage, in the form of cracks in the isolation material or the creation of a microannulus, can allow hydrocarbons to flow to surface or become trapped below the wellhead.

This paper will describe a novel zonal isolation material that responds to a loss of hydraulic isolation. If hydrocarbon flows occur within or around the primary cement sheath, the material will seal these flows and reestablish well integrity. The system, which has slurry properties comparable to standard oilfield cements, is designed to be pumped as part of any primary cementing operation on wells drilled with water or oil-based drilling fluids. This material was used in well construction operations for wells drilled in Eastern Alberta, and can be applied to reduce the incidents of SCVF in this area.

This ability of this system to eliminate hydrocarbon flows has been confirmed with high-pressure laboratory testing, and it has been successfully field tested in Western Alberta.
A Successful Field Experience: Shallow Water Flow—How to Avoid the Need for an Additional Casing String
Authors: Pedersen Rikke , Øian Tore , Haugland Trond , Watts Ben , Taoutaou Salim , Stakkestad Arild
Published: March 2008

In areas with shallow water flow, additional casing strings are normally set to seal off the water-bearing zone. While drilling the first well in Fram East in the North Sea, the operator used a shallow 20-in. surface casing, but this measure increased well costs and caused a number of later limitations in the well construction process. To avoid these complications in other Fram East wells, the operator searched for alternative solutions.

It selected a cement design with properties compensating for the loss of hydrostatic pressure and thereby preventing the water flowing. The service company carried out extensive designing and testing of the cement formulations. A major challenge was qualifying the final design for a full-scale field test. A third-party laboratory qualified the cement system, using a modified setup of the gas migration equipment. The results were promising.

A dedicated cutting injection well was chosen for the field test. The successful test allowed planning the remaining wells using the new system—with projected savings of more than USD 20 million.

This paper will describe the development of the solution, the design, and testing of the cement formulation, and the full-scale field test performed.
Optimization of Deep Drilling Performance with Improvements in Drill Bit and Drilling Fluid Design
Authors: Black Alan D. , Bland Ronald G. , Curry David A. , Ledgerwood L. W. , Robertson Homer A. , Judzis Arnis , Prasad Umesh , Grant Timothy
Published: March 2008

Full-scale laboratory testing was conducted under a joint industry and Department of Energy program titled "Optimization of Deep Drilling Performance; Development and Benchmark Testing of Advanced Diamond Product Drill Bits and HP/HT Fluids to Significantly Improve Rates of Penetration." In total, seven bits and twelve different drilling fluids were tested in three different rocks at a variety of drilling parameters. Phase 1 results have been reported in a previous paper (Judzis et al., 2007). This paper presents the results from Phase 2 of the study. The goal of Phase 2 testing was to evaluate bit features and mud additives that might enhance ROP under high-pressure conditions. The test protocols developed in Phase 1 to simulate Arbuckle play and Tuscaloosa trend drilling at pressures in excess of 10,000 psi were employed to evaluate these features. Significant findings of Phase 2 include the following: Mud additives can substantially enhance ROPs in high-pressure conditions and may play a larger role than bit design features.A 16-ppg cesium formate brine increased ROPs 100% as compared to 16-ppg oil-based mud in Carthage marble and Mancos shale. The cesium formate improved ROPs by increasing both the efficiency and the aggressiveness of the bit.A 16-ppg oil-based mud weighted with fine particle size (D50 ≈ 1-3 microns) manganese tetroxide increased ROPs in Crab Orchard sandstone 100% as compared to a similar mud weighted with conventional barite. The manganese tetroxide improved ROPs by increasing the efficiency of the bit, but did not have a measurable effect on bit aggressiveness.Phase 2 tests continue to support the conclusion of Phase 1 that specific energy consumed while drilling is substantially higher than the confined compressive strength (CCS) of the rock.
Deepwater Exploration Well Pre-Drill DST Sanding Potential Prediction Using Probabilistic and Deterministic Approaches
Authors: Yi Xianjie , Sabolcik James E. , Goodman Harvey E. , Walton Brent W.
Published: March 2008

Sand control decisions are often made based on a deterministically predicted Safe Drawdown Pressure (SDP) without proper regard to the amount of uncertainty associated with the value of SDP. These uncertainties can be large when planning a Drillstem Test (DST) for a deepwater exploration well. On one hand, predicting too low of a SDP for a DST can result in unnecessary sand control. On the other hand, predicting too high of a SDP can lead to sanding during the test, which can cause numerous problems and ultimately cost much more than a sand control installation. Thus, a probabilistic study is warranted to quantify the expected sanding risk through a SDP probability profile, which can be used to estimate the risked expected value of a decision to install sand control or not.

In this study, data from 12 offset wells in nearby blocks from an Offshore Nigeria exploration well were reviewed. First, a regional geomechanical model (in-situ stress, pore pressure and rock mechanical properties) was calibrated and validated based on offset data. The calibrated geomechanical model was used with a sanding prediction model and was calibrated and validated based on offset DST and sand control data. Next, a statistical analysis of regional in-situ stress, sand pressure and rock properties for different sand intervals was performed to generate the necessary Probability Distribution Functions (PDF) and used as inputs to a SDP Monte Carlo simulation. And finally, a deterministic approach was also used to predict SDP. A comparison of Monte Carlo simulated SDP distribution and the deterministically predicted one from offset wells indicates consistent results. The SDP PDF allows estimation of the expected values for installing sand control or not and improves judgments of the true cost of obtaining the DST information.
New-Generation PDC Bits Allow Drilling at Record Rates of Penetration and Increased Durability in Challenging Algerian Applications
Authors: Aliko Enis , Hunt Terry , George Mathews , Nicol Jon , Christensen Hughes
Published: March 2008

Extensive research and development has produced a new generation of PDC bits, designed to drill harder and more abrasive formations than standard PDC bits, including those with the latest abrasion-resistant cutters.

The new-generation PDC bits allow drilling of formations that once were only drillable with TCI roller-cone bits and impregnated diamond bits. The success demonstrated in Algerian applications is likely to spread throughout the world, raising the performance bar and expectations for PDC bits.

The first new-generation PDC bits were introduced in a 12 1/4-in. Jurassic-Cretaceous application in the Algerian Sahara desert and immediately set performance records in one of the area's difficult fields. This application is characterized by a 2000-m long vertical section usually drilled with packed rotary BHAs through a variety of formations ranging from soft and abrasive to very hard. The challenge in this area for PDC bits is drilling the whole section in one run and maximizing the ROP. This challenge is made more difficult by a series of interbedded hard/soft formations that generate extensive vibrations. There also are extensive abrasive layers, leading to premature cutter wear and loss of aggressiveness and ROP.

In this paper, the authors will describe the technologies that were developed and included in these new PDC bits, as well as the field results in a specific application in the Algerian Sahara desert. The authors also will illustrate the importance of applying the correct operating practices in the achievement of record ROPs.
A Step Change in Total System Approach through Wired Drillpipe Technology
Authors: Nygaard Vebjørn , Jahangir Mohammad , Gravem Trond , Nathan Eugene , Evans John , Reeves Mike , Wolter Henrik , Hovda Sigve
Published: March 2008

The demand for increased oil and gas recovery requires the drilling of complex extended reach wells with optimized reservoir exposure for production and minimized overall production costs. In order to achieve these objectives, the use of high-end drilling and logging technology to optimize well placement is of the essence. However, the optimal utilization of this technology is often limited by the real-time transmission bandwidth of essential data from and to the downhole tools. The introduction of wired drillpipe technology has facilitated a step change in two-way data communication resulting in a high-speed data transmission giving much greater volume, resolution and quality of formation evaluation data and drilling dynamics data. Furthermore, the direct control of rotary steerable tools has now been enhanced to allow instantaneous programming changes and better utilization of dynamics data to enhance the decision making process required to address drilling dysfunction challenges, hole quality, gross ROP and BHA reliability.

The high bandwidth technology was used while drilling two laterals on the Troll field's reservoir in the Norwegian North Sea in 2007. The memory quality data was transferred through wired drillpipe to the surface while geosteering through relatively unconsolidated sandstones with localized zones of hard calcite cementation. The bottom hole assembly employed, comprised multiple formation evaluation and dynamics sensors to fully understand the downhole drilling conditions. The data was transferred to the expert advisory centre onshore for advanced processing and interpretation to enable the critical decision making process.

The adoption of a Total Systems Approach to select the ideal combination of application-specific drill bit, drilling system, and appropriate procedures and practices was presented and described by Stavland, et al (2006). Realizing the full benefit of the approach has been hampered by bandwidth restriction and time lag associated with conventional mud pulse telemetry. This paper will discuss how wired drillpipe technology has been utilized to enhance the Total System Approach concept during the first tests and how it will affect operations going forward.
Offshore Field Test of a New Integrated System for Real-Time Optimisation of the Drilling Process
Authors: Iversen F. P. , Cayeux E. , Dvergsnes E. W. , Ervik R. , Byrkjeland M. , Welmer M. , Torsvoll A. , Balov M. Karimi , Haugstad E. , Merlo A.
Published: March 2008

A new drilling control system enhancement for real-time optimization and automation control has been installed on the rig and tested in passive mode in preparation for a full-scale drilling test. The testing has been performed on the Statfjord C platform in the Norwegian sector of the North Sea.

The aim of the field test is to demonstrate that the incorporation of real time calibrated process models in drilling control can make the drilling process more reliable, increase efficiency, and improve safety for the drilling crew and with regards to control of the drilling process.

The system, described previously, performs continuous optimization of operational parameters using calibrated dynamic process models. Safe operational windows are calculated, and operational sequences are automatically optimized through forward model simulations. The results are applied to machine control in real-time, providing process safe-guards and increasing process efficiency.

A thorough description of the preparations and passive testing is given. The final test results are to be evaluated based on success criteria developed prior to the test in cooperation with field operator and drilling contractors. The implications for the work organization are also discussed, particularly in relation to control of data input, decision making and responsibility.

This technology will allow for direct integration of the know-how and best current practices into the drilling control system. Automated procedures and tests are to provide improved control of well conditions. Direct integration of process models shall enable safe optimization in the short time scale. And coupling the system to remote input will enable optimization in the long time scale, while built-in monitoring and diagnostics may ensure safe application of optimised parameters.
Successful Field Appraisal Well Makes Single-Diameter Wellbore a Reality
Authors: McKee Rob , Fritsch Jerry
Published: March 2008

Developing revolutionary technology requires persistence, perseverance, and vision to take an idea to a reliable product. A key factor in achieving the objective stems from how effectively the product development philosophy garners real results. For the development of the single-diameter wellbore, this philosophy resulted in a phased process that brought the technology from a concept to a reality.

This technology had to undergo final validation of some of the components before entering the final phase of the development process. This phase consisted of qualifying the tool for a specific application, with all of the components having been previously qualified for functionality. Successful integrated testing on the single-diameter system resulted in qualifying the phased-expansion system. The field appraisal test recently completed simulated the deployment operations by replicating hole angle, hole size, mud types, drill bits and other variables that factor into the complexity of the downhole conditions.

This paper will explain the product development philosophy and process used to drive the validation of the singlediameter wellbore. It will detail the current status of the technology, the process to determine quantifiers and the actual field appraisal and results. In addition, this paper will explain the factors that led to the product development and determined the commercial viability of the technology.
Solid Expandable Tubular System Mitigates High-Pressure Zones with Record Length
Authors: Bagley W. H. , Schultz Don , Mueller Joe , Vondenstein Marcus , Chowdhary Harsh
Published: March 2008

Dealing with higher than planned pore pressures, slim drilling margins and depleted zones in the same wellbore can quickly compound an already difficult deepwater drilling environment. Current market demands for oil and gas are placing more focus on deepwater development of existing reserves. Operators have had to utilize enabling technologies that are robust enough to address multiple problems to develop deepwater reserves that are difficult to access.

This paper describes a recent example of this dilemma when a deepwater operator successfully employed a solid expandable tubular system to isolate both overpressured and depleted sands The solid expandable system facilitated reaching the well objectives with a large hole size for maximize production rates. Over 6,865 ft (2,092m) of 7-5/8 × 9-5/8 in. expandable openhole liner allowed the operator to drill through both overpressured and depleted sands to an intermediate and unplanned casing point. Subsequent drilling operations below the expandable liner enabled the operator to reach the target zone and case the well with a 7 in. flush-joint production liner. Without the expandable installation, the operator would have been restricted to a maximum 5-1/2 in. casing at total depth (TD). Comparatively, 7 in. casing allowed the use of larger completion equipment providing Nexen Petroleum U.S.A., Inc., with significant additional production while reducing the mechanical risks associated with working inside smaller casing.

The solid expandable tubular operating envelope provides a robust technology for operators who need a responsive system that addresses conditions proven to hinder drilling objectives. This paper will describe the conditions that led to selecting the solid expandable solution and detail the challenges mitigated with the installation of this record-setting system. In addition, this paper will focus on how solid expandable tubulars are applicable in extremely difficult drilling conditions and also how these tubulars can reduce the risks and costs associated with deepwater drilling.
Simulations Comparing Different Initial Responses to Kicks Taken During Managed Pressure Drilling
Authors: Das Asis K. , Smith John Rogers , Frink Philip J.
Published: March 2008

An industry-supported research project to investigate a practical basis for comprehensive well control procedures for managed pressure drilling (MPD) operations is in progress. This paper will describe the results of a simulation-based study comparing alternative initial responses to a range of kick scenarios. The primary responses considered were increasing casing pressure while continuing circulation, increasing the circulating rate without increasing casing pressure, and shutting in the well conventionally. These were investigated using a transient, multi-phase flow simulator. The purpose of the study was to provide a basis for determining the most effective initial response for controlling a kick taken during MPD.

The results have helped to identify several important considerations. One important consideration was expected: the ability to minimize casing pressure and therefore the risk of lost returns by continuing to circulate rather than shutting in. There are significant complications if lost returns occur. Loss of returns is difficult to detect in a shut in well if a float is used. With an initial response based on increasing casing pressure until flow out is equal to flow in, it can be difficult to determine whether formation influx has stopped or partial lost returns are offsetting the influx. In cases with narrow margins between pore and fracture pressure, small differences in the drillpipe pressure being held constant during circulation with lost returns can potentially cause results ranging from total lost returns to uncontrolled flow at the surface. The location of the loss zone relative to the kick zone is particularly important in influencing these results. The need for a practical method of identifying lost returns during the initial response is evident, especially when working in a narrow window between formation and fracture pressure gradients. Simulation results are used to exemplify these considerations.

A tentative result of this on-going study is that there may be no single best initial response to a kick taken during MPD. The best response may depend on well geometry, kick zone productivity, and likelihood of lost returns.
Quick Intervention: Going Lighter and Running Faster with Gastight Rotary Shouldered Connection!
Authors: Griffin R. C. , Plessis G. , Chin D.
Published: March 2008

This paper presents the development of an intervention riser that incorporates a modified second-generation rotary-shoulder connection (RSC). This double-shouldered connection features a high-pressure, gas-tight metal-to-metal radial seal, a secondary back-up resilient sealing barrier and additional modifications to cope with subsea conditions. The comprehensive effort to design, test and qualify the intervention riser for operation in offshore Australia is detailed. Results from extensive finite-element analysis, laboratory tests, manufacturing processes and field results are presented.

Subsea completions and the need for subsequent interventions have dramatically increased in number since the first subsea trees were installed in the 1960s. Intervention on subsea wells requires the deployment of intervention riser systems. Previously, bolted-flange drilling risers were used for most interventions. This resulted in limitations and in most cases was overkill. Drilling risers are heavy pieces of equipment that require special handling equipment as well as taking extensive time to be assembled and deployed. The increased deck load also requires larger workover vessels.

The process of this 15-month project was the design, testing, manufacture and deployment of the project-specific, performance validated, RSC intervention riser system. The riser was successfully placed in service and utilized in the Enfield oil and gas wells offshore Australia.

The use of a lighter, faster and more user-friendly intervention riser system based on RSC technology will reduce time and operational costs while meeting the intervention needs. The gas-tight, metal-to-metal seal RSC is robust, easily handled and incorporates familiar drill pipe handling and running equipment.
Novel Stabilizers for Casing Drilling Simplify BHA, Handling, and Cost
Authors: Limbert David , Langford Steve , Prideco Grant , Gammage John
Published: March 2008

A novel technique for building stabilizers and wear bands directly onto casing for drilling is replacing multiple machined integral stabilizers. This is achieved with spray metal technology and the resulting blades, ribs and bands are at least as wear resistant as steel. Multiple stabilizers can be built onto a single joint of Range 3 casing to create the desired BHA.

The spray metal process is commonly used in other industries for corrosion and erosion protection using relatively thin layers. The novelty of this new process is that the wear metal can be built up, typically, to thicknesses of ¾" (19 mm) and in any desired shape. This is a new use of the spray metal process for casing drilling because it has already proved successful in protecting drill pipe tube from wear in Extended Reach wells and in highly abrasive formations.

Laboratory and field test results indicate that the material is sufficiently robust to withstand normally anticipated downhole drilling forces and the open hole wear resistance testing indicates that it will deliver very satisfactory rotational and longitudinal resistance to abrasion. In one well drilled with casing the casing string was deliberately tripped at TD to inspect stabilizer integrity and to measure wear. Further laboratory work has been undertaken to compare the material's wear and frictional characteristics with plain tooljoint steel and some more commonly used wear resistant materials.

Casing drilling hundreds of wells per year will benefit significantly from the economies of scale which this new process offers. A single joint of Range 3 casing with the necessary stabilizers formed directly upon it is utilized instead of multiple short integral blade stabilizers (IBS) and casing pup joints. Rig time and HSE exposure is reduced through simplifying the BHA and its associated make up procedure. The spray metal stabilizers also provide operators with a significant cost reduction from traditional IBSs.
Design and Qualification of Critical Landing String Assemblies for Deepwater Wells
Authors: Cantrell Andre John , Beiriger Christine Noel , Hubbard Brad Lee , Everage DeWayne
Published: March 2008

Qualification of landing strings has become a major concern for oil industry operators as longer and heavier casing, tie-back or liner sections are required in deepwater and ultra-deepwater wells. Total buoyed weights are currently approaching two million pounds, making it imperative that every component in the landing string assembly is properly qualified.

Any process which qualifies a landing string assembly must be multi-faceted, consisting of both design verification and a subsequent "fit for purpose" inspection. Experience has proven this approach is absolutely necessary to confirm all design assumptions hold true. Over the past six years, a systematic, field-proven, and reliable qualification process has been developed which has allowed operators to successfully land assemblies with buoyed weights up to 1.6 million pounds in water depths from 2,850 feet to almost 9,000 feet on semi-submersible rigs and drillships.

This process addresses critical design considerations such as verification of specialty tool ratings, the effect of makeup torque on connection capacity, appropriate usage of existing slip crushing calculation methods, heave-induced dynamic loading, and minimizing the probability of plugs becoming lodged in the assembly. Inspection issues addressed include coverage and scheduling, traceability to ensure accurate material properties are used in all design calculations, full-length ultrasonic testing of the drill string, and proper inspection of components which are routinely inspected incorrectly.

This paper details the most relevant aspects of this field-proven process, and reviews the implementation of this process by an operator for use on a broad range of casing and liner landing operations. The paper provides a concise summary of the approach that will allow the reader to confidently design for ever heavier loads while preventing costly (yet avoidable) failures during landing operations.

Introduction

Qualification of any landing string assembly requires the following steps be taken for each component:The design of the component is verified to have sufficient capacity for the anticipated loads. This can be accomplished either via classical engineering analyses, load testing of design prototypes, or a properly conducted finite element analysis (FEA).Material properties must meet the specified minimums used in all design calculations. Of primary concern for a landing string component is yield strength, but ductility and impact toughness are also critical for components with stress concentrators.The component must be properly inspected to ensure that prior service has not rendered it unfit for use in the given landing operation, and that all critical dimensions match those used when the component's capacity was verified.When deployed, the tool must be properly assembled within the landing string assembly.
Surface BOP System for Subsea Development Offshore Brazil in 1,900 m of Water
Authors: Tarr B. A. , Taklo T. , Hudson A. , Olijnik L. A. , Shu H. , Greff R.
Published: March 2008

A surface BOP system with a seabed isolation device (SID) was successfully used to extend the water depth capability of the D.P. semi-submersible rig Stena Tay for exploration drilling activities in ultra-deep water to 2,887 m offshore Brazil and to 2,447 m offshore Egypt in 2003. This provided the necessary experience to take the next step towards reducing the cost of deepwater developments utilizing a surface BOP system deployed from an earlier generation, lower specification, deepwater rig.

This paper presents the configuration and specifications developed for the surface BOP drilling and subsea completion system to be deployed offshore Brazil in the first phase of the Parque das Conchas development (block BC-10) that encompasses several reservoirs in up to 2,100 m of water.

The rig selected for the project had to meet certain minimum requirements to safely deploy the planned surface BOP system, and these requirements led to the selection of the Arctic I, a moored rig capable of operating in 945 m of water using a conventional 18-3/4" subsea BOP stack and marine riser system.

The new elements incorporated in the surface BOP system include: Site specific pre-laid polyester taut-leg mooring systemSlim-bore wellhead system (to land production casing hanger)Purpose built 16" OD high pressure riser system (to replace casing riser)Added pressure test hose line, strapped to riser (to pressure test tubing hanger & packer)Replaced lower shear ram in SID with fixed 7-5/8" pipe ram (to seal on ported slick joint)Added power and hydraulic lines in SID umbilical (to reduced ROV support needed)Vertical subsea tree, Tubing Head Spool and slim bore tubing hanger with hydraulic running tool

Development drilling operations with this surface BOP system are now expected to commence in the first quarter of 2008.
Dipole Radial Profiling and Geomechanics for Near Wellbore Alteration Detection to Improve Productivity in a Matured Field
Authors: Subbiah Surej , Wielemaker E , Joia P , Hopper L , Fernandez LI , Kongslien M , Edwards N
Published: March 2008

Cartojani is a mature oil field with depleted reservoir pressure, supported by an aquifer in the deeper Cretaceous horizon. The Cartojani structure is located in the central alignment of the Moesic Platform. It is a monocline with large dimensions and low layer inclinations. The main hydrocarbon accumulation is found in the Sarmatian formation (Base Cretaceous Paleorelif) at the depth of 1100 to 1150 m. Currently the main productive horizons are sands from the lower Sarmatian (Basal Sarmatian). The facies variation can be seen both vertically and horizontally on a well-to-well basis even though the wells are very closely spaced. Sands have different oil retainer capacity and flow from clean to dirtier sands. The lower most units comprise of unconsolidated sands that are thinly distributed. These unconsolidated sands are normally completed using cased hole gravel pack. In order to select optimal completions, it required both identification and estimation of the radial extent of the nearwellbore mechanical alteration that might cause near-wellbore permeability impairment. The near-wellbore alteration, characterized by radial profiling of formation shear, can be correlated with the skin effect and reservoir productivity index. Due to the nature of the formation, formation damage is expected to be one of the main challenges to counter the observed decreasing production. A new dimension has been added to sonic measurements, providing measurements in several dimensions: axial, radial, azimuthal. The radial measurements provide now the opportunity to determine whether the near wellbore experienced any alteration. The sonic data was processed to extract a very reliable compressional, shear and Stoneley. Dispersion analysis confirmed the presence of alteration to the formation. Dipole radial profiling then demonstrated that in fact a 5 inch altered zone was present in the unconsolidated sands. Using the sonic data, mechanical properties and stresses were calculated. The unconfined compressive strength (approximately 200 to 300 psi) values demonstrated that in fact it concerned very unconsolidated sand. Using the mechanical properties together with the possibilities for perforation design, detailed analysis was performed. The analysis showed that the traditional gun selection would not surpass the skin and that in fact if would require deep penetrating charges with big hole (to minimize sand production). A proper gun system was selected based on the analysis. To improve the wells productivity, deeper penetration and high shot density guns were selected as a perforating method, to pass the radial extent of near - well bore mechanical alteration. After perforation, the production test showed a 3-fold increment in production compared to the previous best producers in the field. The skin estimation based on the model compared very well to the measured values during production tests.