bluuebunny/crossref_metadata_2025 huggingface dataset:
Innovative Computer Model Increases Success Rate When Placing Deep Kickoff Plugs in Southern Mexico
Authors: Diaz Lenin Omar , Flores Juan Carlos , Justus Frederico , Pasteris Mathieu , Flamant Nicolas , Milne Art
Published: March 2009

Traditionally, service companies have had to place several consecutive cement plugs to successfully kick off wells deeper than 3,500 meters. Within the scope of integrated projects in Southern Mexico where wells are usually deeper than 5,000 meters, the low success rate for traditional balanced plug cementing has jeopardized operational efficiency and financial results. Several plug failures made it clear that the volumetric calculations and other known engineering best practices that were implemented were not sufficient to bring the success rate to an acceptable level. In our field study, we implemented an innovative simulation and design method that allows for engineered optimization of the plug placement design and that shows how a 100% success rate in plug cementing can be achieved in wells as deep as 5,720 meters, with hard formations and an OBM environment. The value of this new method resides in a live analysis and display of the fluid interfaces, mixing both while traveling down the pipe and up the annulus and resulting in the output of an estimated top of uncontaminated cement after pulling the pipe out of the hole. The new workflow reveals the effect of each variable affecting the amount of contamination of the cement slurry downhole and gives the engineer the opportunity to optimize the plug placement design before job execution to reach the highest possible top of uncontaminated cement after execution. The results obtained with the new engineering tool and a precise operational field execution has moved the theory of plug placement from the best practice library to the reality of the plug placement operations.
Evolution of Drillable PDC Technology Enables Operator to Safely and Economically Drill South Texas Gas Wells With Casing
Authors: Limbert David , DeGeorge Jarod , Isbell Matt , Doster Mike
Published: March 2009

An operator in South Texas established a casing drilling program in 2002 to address drilling hazards and has since successfully drilled over 200 wells using purpose-built casing drilling rigs. The typical hazards mitigated by casing drilling include lost circulation, tight hole, and depletion. In 2006 and 2007, the operator realized a 15% savings in drilling cost and increased footage drilled per day by 23% utilizing casing drilling technology.

Given their success with casing drilling, the operator was eager to expand use of casing drilling to their traditional drill pipe rigs. This was easily accomplished in the production hole but more complicated in the intermediate hole section. The purpose-built casing drilling rigs used a wireline retrievable bottom hole assembly (BHA) with a pilot assembly and underreamer. This system was proven and reliable, but the wireline retrievable BHAs had several weaknesses. These weaknesses included wireline operation safety, the cost of tools, and underreamer performance. These factors forced the operator to seek an improved solution for this field development.

A cross-functional team from the operator and service company identified the solution as drillable PDC casing bit technology that allowed the drill pipe and the casing drilling rigs to safely, efficiently and economically drill the intermediate hole. The existing drillable PDC casing bit was used primarily for drilling short intervals or for drilling-in liners in relatively soft formations and was not durable enough to drill the entire interval. The authors will detail how the team developed a "heavy-duty" drillable PDC casing bit with a series of test wells to overcome this challenge. This new drillable PDC casing bit allows the operator to improve further drilling in their field development program by enabling casing drilling in the intermediate hole section on their entire fleet of rigs with minimal additional equipment and cost.
Advanced PDC Technologies Deliver Significant Performance Improvements in the Pinedale Anticline Production Interval
Authors: Gent Jonny , Isenhour Jim , Freeman Mark , Hale Matt , Lyons Nick
Published: March 2009

A rigorous engineering and research effort combined with targeted field testing has delivered a new generation of PDC technology. This technology is intended to be utilized for the most technically challenging drilling applications across the globe.

One of the first applications identified for this new technology was at the Pinedale anticline field in Sublette County, Wyoming. At Pinedale, the operator's directionally drilled development wells target interbedded fluvial sandstones and shales of the Lance Pool (Lance and Upper Mesaverde formations).

Due to surface constraints, all wells are drilled directionally from centralized surface pads. To achieve uniform subsurface well-spacing, well trajectory is S-shaped, with all directional work occurring before the pay interval is encountered at approximately 8,500 ft MD. The pay interval is then drilled vertically utilizing 6 1/2-in. PDC bits to approximately 13,400 ft MD, with the final 1,000 ft frequently drilled with diamond-impregnated bits.

The sequence of interbedded fluvial sandstones and shale comprising the Lance Pool presents a difficult drilling environment. The interval is characterized by moderate but erratic unconfined compressive strengths ranging from 10 to 20 ksi exacerbated by high overburden pressures and increased hydrostatic pressures from mud weights exceeding 15 lb/gal to control pore pressure and maintain formation stability. Confining compressive strengths approaching 100 ksi (excluding formation pressures) are not uncommon. These harsh drilling conditions have led to slow penetration rates and short bit runs utilizing conventional PDC designs.

The authors will describe the technologies developed and included in the new PDC bits. These new technologies have reduced the time in this interval by more than 100 hours per well, a 25% improvement over previous designs. With eight rigs running, each rig drilling one well/month, the operator is seeing productivity gains worth 308 days of drilling time over a year's time.
Early Detection of Drilling Conditions Deterioration Using Real-Time Calibration of Computer Models: Field Example from North Sea Drilling Operations
Authors: Cayeux E. , Daireaux B.
Published: March 2009

Abnormal surface torque and hook load values are symptoms of downhole drilling condition deterioration which can result in unexpected situations. Usually, friction tests are performed at regular intervals and rig personnel uses these measurements to monitor trend variations in order to detect possible risk of poor hole cleaning or increased borehole tortuousity. The quality of the detection can vary greatly in function of the work load and experience of the drilling staff. The availability of real-time measurements through data servers make it possible to automate and systemize the monitoring process and therefore trigger alarms before drilling problems really occurs.

This paper presents a computer system used to systematically analyse real-time data in order to monitor downhole conditions. Such a system can utilize much more data than just the above mentioned friction tests, because mechanical, hydraulic and temperature models can calculate predicted hook load and surface torque in any drilling conditions. The numerical models are automatically calibrated (adjustment of drill-pipe linear weight, factors for mechanical and hydraulic friction and heat generation). The evolution of proper calibration factors is used to detect poor downhole conditions. Automatically generated messages are sent to key personnel who can evaluate the potential problems and take necessary actions.

To validate this new methodology, the system has been run on recorded data from three wells on an oil field in the North Sea. A data filtering technique has been developed and applied to solve problems with noisy and erratic real-time signals. With correct input parameters, the system has clearly indicated unexpected measurements several hours before a pack-off problem occurred and therefore proven that the methodology could help in detecting the worsening of downhole drilling conditions.

Availability of large amount of real-time data at the rig site or in onshore drilling centres does not necessarily facilitate the recognition of drilling problems. However, online interpretation systems, as the one described above, can systematically analyze the logged data to detect as early as possible the deterioration of hole conditions during drilling operations and corrective actions can be taken before any major problem has really occurred.
Formation Damage Induced by Formate Drilling Fluids in Gas Bearing Reservoirs: Lab and Field Studies
Authors: Al-Anazi Hamoud A. , Bataweel Mohammed A. , Al-Ansari Adel A.
Published: March 2009

Formate-based drill-in fluid was used for the first time to drill gas wells in Saudi Arabia. Gas wells were completed in sandstone reservoirs where temperature ranges between 270–310° F. Na/K formate mud was used to drill these wells with required mud weight ranges between 88–105 pcf. Thorough experimental studies were conducted to optimize mud formulation to meet drilling operation requirements and to explore possible induced formation damage. Compatibility tests were performed on formate system with formation brine. Corrosivity of formate brine was also studied on tubing alloys (CS and S13Cr) using field drill-in-fluids (DIF) at simulated reservoir conditions. Return permeability studies showed that Na/K formate system resulted in a less damage compared to conventional mud systems. The formate drill fluids gave a high return permeability up to 77% after circulating the corresponding washing fluid. Two damaging mechanisms were identified: external filter cake and potassium chloride precipitation. Compatibility tests indicated that precipitate formed due to mixing of filtrate with formation brine that contains large amount of chloride. Lab tests imply that formate brine had low corrosion rate when the pH of the solution was maintained above 9. On the other hand, the corrosivity of K-formate brine increases in the presence of CO2due to the formation of formic acid. The results of this study were implemented on several gas wells. The first gas well drilled with formate brine, before this study, showed severe corrosion problems in the bottom hole assembly (BHA) due to the ingress of CO2 and gave a very low production rate. These problems were eliminated in the other two gas wells by completing them with super Cr-13 and implementing a developed on-site monitoring of DIF.
Reelwell Drilling Method
Authors: Vestavik Ola , Kerr Scott , Brown Stuart
Published: March 2009

A new drilling method has been developed in a Joint Industry Project, funded by StatoilHydro, Shell and the Research Council of Norway through the Demo2000 programme. The new drilling method has the following features: –New drilling tools and procedures for improved downhole pressure control.–Optional drill-in liner for immediate wellbore isolation.–Potential elimination of lost circulation and hole cleaning problems.

The new drilling method combines Managed Pressure Drilling and liner drilling. The method implies the use of a concentric drill string. A downhole sliding piston is attached to the string and used for improved downhole traction and pressure control. Several full scale drilling trials at the test rig "Ullrigg" in Stavanger have successfully demonstrated the main features of the new concept and its unique possibilities for improved pressure control and drilling performance.
How Continuous Improvement Lead to the Longest Horizontal Well in the World
Authors: Sonowal Kumud , Bennetzen Bjarne , Wong Patrick , Isevcan Erhan
Published: March 2009

Maersk Oil Qatar AS (MOQ) completed drilling the world record BD-04A well in May 2008 offshore Qatar. This was the successful outcome of engineering efforts to increase extended reach capabilities.

MOQ started to develop the Al Shaheen Field offshore Qatar in 1994 with the application of horizontal drilling techniques, pioneered by Maersk Oil & Gas AS in the North Sea. In 1994, 10,220 feet was the longest horizontal length drilled by MOQ. In May 2008 the BD-04A well was completed with a record horizontal length of 35,770 feet. This well also set new world records for both the longest well at 40,320 feet MDRT and the longest along hole departure of 37,956 feet.

The introduction of new techniques has allowed existing constraints to be successfully challenged and overcome. This was achieved through the application of sound engineering principles and continuous optimization during the field development phases.

This case study will review the history, challenges and planning, leading through to the successful drilling of the BD-04A well. The paper will outline the achievements, improved practices and the engineering analysis of field data where key learning points have been shared for future use and applications. It will show that even when constrained by certain limitations such as rig capacity, major step changes can be achieved by optimizing basic operating parameters. In addition to the world record, several other accomplishments have also been achieved in this well as detailed in this paper by using state-of-the-art horizontal drilling technology.

The paper will not only contribute directly to the industry's knowledge base related to improving hydro carbon recovery through extended reach horizontal wells but also set an example of how operating envelopes can be extended by continuously challenging existing practices.
New Riser Design and Technologies for Greater Water Depth and Deeper Drilling Operations
Authors: Persent E. , Guesnon J. , Heitz S. , Averbuch D.
Published: March 2009

IFP has developed innovative technologies to answer the needs expressed by the oil and gas industry that wish to perform drilling operations in deeper water depths, in harsher environments with higher mud density. A new generation of drilling risers is proposed based on a combination of technologies which provide the riser with much higher performances for tension, pressure and dynamics: ■steel / composite hybrid Choke and Kill lines to withstand high pressures■axial load-sharing between the main pipe and the auxiliary lines to improve the riser's mechanical behavior.

A wide riser design parametric study was therefore performed considering 20 operational conditions. Five water depths from 6,000 ft to 14,000 ft and drilling depths in the range of 20,000 ft to 44,000 ft were considered. On the basis of three main operational requirements (riser mass, buoyancy limitations, riser natural period), the operational working envelopes of a new generation of risers were compared to those of conventional risers.

According to the hypotheses of the study, it appears that the current drilling riser technology is generally limited to a 10,000 ft water depth and a 25,000 ft total depth in heavy rock formations. The dynamic behavior of such long risers, their huge mass and the buoyancy that are required to withstand high pressure encountered at greater drilling depths, strongly penalize the use of conventional riser technology beyond these limits.

The paper shows how the HyperStatic Integration (HSI) concept and the hybrid pipe technology significantly extend the operating working envelopes of the riser. They introduce major improvements in the riser design such as: ■a large reduction of the riser mass and of the required buoyancy for riser joints■an improved dynamic behavior which reduces the risk of riser resonance and increases its fatigue life.

These new technologies therefore allow drilling operations in greater water depths, up to 14,000 ft, and deeper total depths beyond 30,000 ft. Since the qualification of hybrid pipes is now well advanced, further work is being carried out to develop and qualify the HyperStatic Integration techniques in order to have the technology ready for industrialization early in the next decade.
Novel Concentric Expandable Stabilizer Results in Increased Penetration Rates and Drilling Efficiency with Reduced Vibration
Authors: Radford Steven , Li Tracy , Jenkins Mark
Published: March 2009

Technological improvements of drilling and reaming methods continue to be evaluated and introduced to the drilling industry. This paper describes recent, controlled testing of new expandable concentric stabilizers and reamers, performed on a full-scale, highly instrumented drill rig.

An inherent problem of drilling and reaming concurrently is that conventional fixed stabilizers run above expandable reamers can be no larger than the pass-through diameter of the restriction above it and thus cannot effectively stabilize the upper BHA, which often results in undesirable vibrations. However, recent controlled tests have been conducted in twin wells drilled from the same casing under a full-scale drilling rig, one well with only a concentric expandable reamer and the other with both expandable stabilizer and reamer. The testing has shown that utilization of this novel stabilizer produces significant gains in performance.

BHA modeling predicted lower bending moments above the reamer when a concentric stabilizer was utilized. The well drilled with the stabilizer above the reamer resulted in higher ROP with lower downhole WOB and up to 35% reduction in drilling mechanical specific energy (MSE), as compared to the well drilled without the expandable stabilizer. The stabilized well had significantly better drilling efficiency, which is attributed to reducing buckling and whirl in the drill pipe and upper BHA, and reduced frictional losses against the borehole wall. Additionally, lower levels of whirl, lateral and stick-slip vibrations were recorded with the new expandable stabilizer.

The paper describes the novel design features of this expandable stabilizer, which are credited with the step-change improvement in drilling efficiency. Monetary savings from increased drilling efficiencies and improved reliability are anticipated for operators and will be discussed in this paper.
Guidelines for Appropriate Application of Non-Foamed Ultra-Lightweight Cement Slurries
Authors: Dajani Ragheb , Curtis James
Published: March 2009

Technological advances in well cementing have made possible the use of ultra-lightweight (ULW) cement slurries with densities as low as 7.5 ppg, without foaming. These ULW slurries often achieve significant compressive strengths, even at moderate or low curing temperatures, such as in deep water environments. However, there are plenty of opportunities for disaster to occur when conventional cement slurry design criteria, laboratory testing procedures, and field practices are inappropriately applied to ULW cementing applications.

This paper will discuss the relevant issues that must be taken into account when planning a successful ULW cement operation, including materials selection, liquid volume fraction, surface and downhole densities and rheologies, compressive strength testing procedures, quality control measures, blending and bulk handling, operating error margins and on-the-fly mixing control systems.

As drilling activity continues to grow into depleted and low fracture gradient areas, especially in the offshore developments, adherence to the guidelines proposed in this paper will serve to improve the likelihood of successful ULW cementing operations.
Along String Pressure and Temperature Measurements in Real Time: Early Field Use and Resultant Value
Authors: Hernandez Maximo , Johnson Monte
Published: March 2009

High-speed drill-string telemetry technology is being adopted with increasing frequency into challenging drilling environments around the world. In addition to allowing instantaneous upward and downward transmission of data between surface and measurement tools located close to the drill bit, this technology also enables measurements to be acquired and transmitted to surface from many points along the string while drilling.

Real-time along-string annular pressure and temperature measurements have strong potential to provide never before seen visibility of the dynamics of drilling cuttings cleaning, equivalent circulating density (ECD) and fluid influx/loss issues at multiple points along a wellbore. In many cases this information is dramatically different from traditionally held assumptions and can be used to more effectively manage flow rates, mud weight, rate of penetration (ROP), string rotation and the use of lost circulation material to significantly reduce the risk of stuck pipe, formation fracture and excessive losses.

This paper shares and discusses previously unseen data from early field uses of along string pressure and temperature measurements with comparisons to normally available data from bottom-hole measurement tools. Particular attention is paid to the drilling decisions taken based on this additional information and the impact of those decisions on efficiency and well cost.
Case History: Successful Wellbore Strengthening Approach in a Depleted and Highly Unconsolidated Sand in Deepwater Gulf of Mexico
Authors: Fett Darryl , Martin Frederic , Dardeau Claude , Rignol Joel , Benaissa Saddok , Adachi Jose , Pastor Jorge
Published: March 2009

In early 2008, Total E&P-USA sidetracked the Mississippi Canyon 243 #A2 well on its "Matterhorn" TLP, in deepwater Gulf of Mexico. A pre-project geomechanics study identified that the mud weight/fracture pressure window in the depleted and highly unconsolidated ‘A’ reservoir was very narrow, creating a strong potential for mud losses during drilling and cementing the 7" liner. The risk of losses was a primary concern since the well would be frac-packed, and if a competent cement column did not reach a sufficient height, the ability to fracture the reservoir would have been compromised. To mitigate this risk, the decision was made to drill through the depleted reservoir using a ‘flat rheology’ synthetic-based fluid, engineered with a high concentration of bridging particles to impart a strengthening effect on the formation.

The ‘designer fluid’ allowed the reservoir to be drilled through successfully, and the 7" liner to be run and cemented with full returns. Analysis of the frac-pack data showed that the formation breakdown pressure was lower than the wellbore pressures experienced while drilling and cementing the liner, suggesting that the designer fluid improved the fracture resistance of the formation. The results imply that using such a designer fluid can have a strengthening effect on depleted/unconsolidated formations, in which some operators have had limited success applying wellbore strengthening techniques.

The implication for the industry is that this technique can and should be considered on wells with similar challenges and risks as the Matterhorn A2 well. This paper will describe the approach taken in the laboratory for the fluid design, as well as operational practices to apply the treatment on location. A post-mortem analysis will compare formation breakdown pressures taken from the fracturing operations to actual wellbore pressures experienced while drilling and cementing, to demonstrate that a strengthening effect was realized.
Enhanced Real-Time Wellbore Stability Monitoring Using High-Definition Imaging With Wired-Pipe Telemetry
Authors: Wolfe Chris , Morris Stephen , Baule Ansgar
Published: March 2009

Many fields currently being drilled by the petroleum industry require the use of high angle, extended reach wells to access remote hydrocarbon deposits. Although pre-drill geomechanical modeling efforts are often carried out to define the mud weight window, many wells still experience significantly elevated drilling costs due to non-productive time (NPT) associated with wellbore instability. This can be attributed to many factors but is predominantly due to the lack of appropriate data while drilling. Since rock properties, stresses and pore pressure often vary from the pre-drill model predictions, critical wells frequently require real-time updating of the geomechanical models using relevant logging while drilling (LWD) data to facilitate accurate, real-time decision-making. In this paper, a case history is presented where memory-quality; high-definition LWD image logs were obtained via high-speed telemetry systems and used to assess wellbore conditions in real time. The high-resolution LWD images were used to detect faults/fractures, breakout and general hole enlargements. Relog images over known unstable sections were also obtained to ascertain the extent of time-dependent wellbore failure. These logs were successfully used to delineate the failure zones and apply the appropriate mitigating actions in real time.
BP Egypt uses RMR on Jack-Up to Solve a Top-Hole Drilling Problem
Authors: Hinton Andy , Seim Kjartan , Becker Gerhard , Kvalvaag Edvin , Jongejan Arthur
Published: March 2009

BP Egypt used a subsea pumping system on the Rahamat 1 well so that engineered mud could be used to drill the surface hole with returns to the Constellation II rig bypassing a large air gap. This was the first use of Riserless Mud Recovery (RMR) on a jack-up. It allowed 26" surface hole to be drilled and 22" surface casing to be set at 3755ft (1144m) Below Mud Line (BML) without major problems.

Firm sand prevents a 30" conductor being driven deeper than 167ft (51m) BML. The rig has a large, 130ft (40m), air gap and the water depth is just 62ft (19m). The result is a conductor shoe that can only support a column of 7ppg (0.8SG) fluid back to the rig. Inhibited mud, minimum weight 9.4ppg (1.13SG), was needed to control the formations. Seabed returns were unacceptable for environmental and mud supply reasons.

RMR installation / retrieval was mainly done off the critical path and did not need an ROV. The system took returns from the conductor at sea level and pumped mud with cuttings back to the rig. Mud was re-circulated after treatment. This allowed good control of the mud properties. Equivalent Circulating Density (ECD) pressure was reduced by (a) 3.5ppg (0.4SG) at the casing shoe and (b) 0.3ppg (0.04SG) at section TD compared to a full column of mud back to the rig. Mud losses in coarse sands were controlled by adding Lost Circulation Material (LCM) and fluid loss control material. The 26" hole was drilled to the planned depth. 22" casing was run and cemented while controlling the fluid level in the annulus (and therefore downhole pressure) with RMR. No losses were seen during these operations.

RMR allowed surface hole to be drilled with mud and returns to the rig because RMR removed the effect of the 130ft air gap. The alternative well design needed an additional liner, taking 20 days and costing US$10million (based on previous well). The additional advantage was that engineered mud was used throughout the surface hole resulting in greater hole stability.
Axial Force Transfer of Buckled Drill Pipe in Deviated Wells
Authors: Menand S. , Sellami H. , Bouguecha A. , Isambourg P. , Simon C.
Published: March 2009

Axial force transfer is an issue in deviated wells where friction and buckling phenomenon take place. The general perception of the industry is that once drill pipe exceeds conventional buckling criteria, such as Paslay-Dawson, axial force cannot be transferred down-hole anymore. This paper shows that, even though buckling criteria are exceeded, axial force transfer could be still good if drill pipe is in rotation. On the contrary, there exists sliding operations where lockup is observed, due to buckling, even though standard buckling criteria are not exceeded. This paper is intended to show and explain how axial force is transferred down-hole in many simulated field conditions: sliding, rotating, with or without dog legs. These new results have been obtained from an advanced model dedicated to drill string mechanics successfully validated with laboratory tests.

This paper will show applicable results for practical well operations where axial force transfer is an issue. These results will enable to give some guidelines to help the drilling engineer to select cases where conventional buckling criteria should be used cautiously. Indeed, simultaneous torque-drag-buckling calculations show that tubular can tolerate significant levels of compression, enabling to provide weight transfer to the drill bit, even though drill pipe is buckled. Others examples, in contrast, show that standard buckling criteria cannot predict the occurrence of buckling that may cause tubular lockup while tripping in the hole.

The applications of these results are numerous for all deviated wells such as horizontal or extended reach drilling wells. This paper should contribute to reduce unpredictable lock-up situations and improve axial load transfer performance.
MWD Vibration Measurements: A Time for Standardisation
Authors: Osnes Svein Magne , Amundsen Per Amund , Weltzin Tore , Nyrnes Erik , Hundstad Brita Lucie , Grindhaug Gaute
Published: March 2009

Since downhole vibration measurements were introduced in the early 1990's, these measurements have become extremely useful for improving drilling efficiency in most parts of the world. Most operators will specify a vibration sensor of some sort to be run with most MWD (Measurement While Drilling) and LWD (Logging While Drilling) applications.

Unlike most other downhole measurements, there is no industrial standard for how to sample, process and present the vibration data. This raises a few issues that this paper attempts to address: Vibration measurements from different companies cannot be readily compared – and it is not known if the different tools and systems will detect the same vibration mechanisms and/or severity of vibrationsVibration Specifications of MWD and drilling tools from different service providers cannot be compared. It is not possible to compare specifications of the various tools as these are given based on the individual service company's internal vibration definitions

This paper looks into the physics and statistics of how four major MWD service providers conduct their vibration measurements.

Even though all the service companies basically can measure the same physical parameters such as tri-axial accelerations and instant changes in downhole RPM (Revolutions Per Minute), the data are handled differently when it comes to the physical understanding of the data, as well as the statistical modelling of the vibration severities. To further confuse the issue, the data is also presented differently and on different severity scales.

The torque/RPM vibration measurement, commonly referred to as "stick-slip", is well documented by previous publications by the different companies (Chen et. al. 2006). The present paper mostly concentrates on how the different MWD companies measure, process, report and interpret their tri-axial data. An analysis is conducted to establish if the various service companies are tuned to look for the same type of vibrations, or whether different vibration patterns tend to be detected with the various procedures in place.

Finally, the need for an industry standard is highlighted, and the MWD industry is challenged to move towards standardisation.
Drilling Wells With Narrow Operating Windows Applying the MPD Constant Bottom Hole Pressure Technology—How Much the Temperature and Pressure Affects the Operation's Design
Authors: Arnone M. , Vieira P.
Published: March 2009

Narrow pore / fracture pressure gradient margins (operating window) is translated as a real drilling hazard scenario, where a slight change in the bottom hole pressure conditions can lead to an increase the Non Productive Time (NPT) due to the time spent in solve a possible fluid losses and/or gas kick situation, or even worst, dealing with occurrence of blowouts. In specific and non rare cases, deep formations with small gap between pore and fracture pressure are un-drillable with conventional drilling practices because the frictional losses pressure (difference between the dynamic and static pressure) is greater than the existent operating window. Constant Bottom Hole Pressure (CBHP), one of a number of variants of Managed Pressure Drilling (MPD) enables "walking the line" between pore and fracture pressure gradient. The objective is to drill with a fluid that bottom hole pressure is maintained constant, whether the fluid column is static or circulating. The loss of annulus flowing pressure when not circulating is counteracted by applied surface backpressure. The basic of Constant Bottom Hole Pressure (CBHP) methodology is to accurately determine the change in bottom hole pressure caused by dynamic effects and compensate with an equal change in annular wellhead pressure. The bottom hole temperature as well as the hydrostatic head of the drilling fluid column increases with the well depth and both parameters have opposing effect in the resultant static and dynamic equivalent density. An increase in the hydrostatic and dynamic pressures increases the equivalent fluid density due to compression but an increase in the temperature causes a reduction in the equivalent fluid density due to thermal expansion. Conventionally, these parameters considered together results in a cancellation of effects. In the reality, this assumption should be carefully reviewed. The effect of temperature in annular pressures, on a MPD CBHP operation through narrow operating windows, can not be ignored due to the potential impact. Precise estimation of static and dynamic equivalent fluid densities is of essential importance for a successful MPD CBHP operation through narrow operating windows.
Drilling Automation: Technologies, Terminology and Parallels With Other Industries
Authors: Thorogood John , Aldred Walt , Florence Fred , Iversen Fionn
Published: March 2009

Drilling Automation is a rapidly developing area of technology that is seeing growing interest within the drilling community. The SPE set up a new Technical Section devoted to the subject as it relates to downhole performance, and the IADC has created a committee with a focus on surface processes.

As with any emerging technology, the associated jargon is evolving rapidly, and different terms are used by different groups to refer to similar concepts with the potential for confusion and misunderstanding. Automation efforts are being undertaken by numerous and diverse organizations and implementation of such interrelated offerings at the rig site need consistent interface criteria at each boundary to ensure efficient and safe operations.

The purpose of the proposed paper is to describe some of the concepts already in operation and under development and to classify them into a number of key categories.

The more significant interface requirements will be identified and key safety concerns will be highlighted. Parallels will be drawn with other industries to demonstrate analogues and suggest directions where and how further developments might be expected to lead.
Further Developments in Drill Pipe Fatigue Management: A Case Study
Authors: Zoanni R. F. , Everage S. D. , Wadsworth T. M. , Cassanelli J. P.
Published: March 2009

Industry advances continue to enable pursuit of more challenging drilling targets with complex well bore trajectories. Many of these targets are in costly deepwater and/or remote operating areas. Demand for a practical, field-proven drill pipe fatigue management system has grown as drill string failures due to fatigue contribute to a significant amount of non-productive time and cost. The response to this demand has been the development of an engineered approach that combines pipe section positioning and inspection scheduling based on estimated fatigue damage rather than rotating hours or footage drilled. Successful real-time field implementation with ongoing drilling programs demonstrates that the cumulative fatigue damage technique is a valuable and proven tool for risk mitigation and cost reduction.

The cumulative fatigue damage technique and its implementation have been introduced in previous literature [1,3,8,10]. This method of monitoring fatigue damage due to rotary operations allows the pipe to be evaluated under real-time operating conditions along a specific section or the entire length of the drill pipe. Monitoring begins at spud and is performed on each joint of drill pipe as it traverses along the well path to total depth (TD). This not only allows a quantitative measure of the relative fatigue damage accumulated joint by joint for the drill pipe, but also provides the opportunity to manage logistics, forecast pipe inspections and position pipe sections to minimize cumulative drill string fatigue damage.

The cumulative fatigue damage technique has been successfully applied in the field[1,10]. Hind casting, pre-drill planning and real-time analyses have been utilized for assessing drill string design as well as pipe management. The current case study further demonstrates the methodology introduced in the previous literature and illustrates the modeling and management of fatigue damage over a three well project. The subject operator originally anticipated that pipe inspection may be required before each well to mitigate costly historical drill pipe failures. However, the cost and logistical challenges of mid-program pipe inspection in remote operations could not be ignored. Described is the pipe management strategy employed to complete the drilling program without drill pipe failures and without the need for any mid-program inspections. In addition, the inspection results post TD of the third programmed well have been evaluated and correlated back to expected pipe damage, making this an excellent case study for the further deployment of this technology.
HPHT Drilling—New Frontiers for Well Safety
Authors: Paula R. R. , Ribeiro P. R. , Santos O. L. A.
Published: March 2009

In a scenario of huge investments in the quest for new oil and natural gas discoveries, the oil industry has reached a consensus: no easy fields to be developed remain undiscovered, especially in offshore environments. New and old challenges on well drilling such as drilled extensions over 6000 m, sub-salt drilling, very narrow operational windows, operational problems like lost of circulation, stuck pipe, and kicks are aggravated when drilling in high pressure and high temperature (HPHT) environments.

In the world's exploratory context, the occurrence of HPHT areas is an increasing trend. It is the materialization of the worst case scenario for well drilling and safety, formed by great challenges and operational, environmental, and economic risks. Field experience has shown that the economical risks have been overshadowed by the great premium target: increments on reserves. However, if the well safety aspect is dealt with the conventional approach, the oil industry is at risk of losing its investments, causing great impacts to the environment and also to the company's image. Since HPHT well construction costs are so much higher than those of traditional wells, the scope of knowledge and science on well safety, once limited to kick prevention and well control contingencies, are now an integral part of the technical and economic feasibility of well construction.

Within this context, this work surveys the best HPHT techniques and procedures practiced by the oil industry, presents the new researches and trends and shares some valuable lessons learned on Petrobras, operations in Brazil and throughout the world.
Kicks in Offshore UK Wells—Where Are They Happening, And Why?
Authors: Dobson J. D.
Published: March 2009

The first well on the UK Continental Shelf was spudded 44 years ago and the area has long been considered a mature province. Despite this, kicks are still a frequent occurrence.

Kicks occur across the entire UKCS area from the Atlantic margins, west of the Shetland Islands to the mature gas fields of the southern North Sea, where the first significant discovery was made in December 1965. Kicks occur in high pressure high temperature condensate exploration wells and in production wells in depleted, sub-normally pressured oil reservoirs. They occur during drilling operations and during work-over operations.

Analysis of data on well incidents held by HSE, the UK regulator, has identified where, geographically, kicks occur most frequently. Analysis also identifies the type of operation being carried out at the time and some of the more significant factors behind the influxes.

The purpose of this paper is to share the regulator's observations with industry. While well operators and drilling contractors hold in-depth information on individual incidents, it is the regulator that is often best placed to observe the wider picture.
Fluid Momentum Balance Defines the Effective Force
Authors: Mitchell Robert F.
Published: March 2009

Once again, the effective force is being scrutinized by the industry. The effective force is a concept developed for including the effects of the surrounding fluids on the pipe. The paper that defined our current understanding of pipe-fluid interaction was written by Klinkenberg (1951), with essential additional discussions by Arthur Lubinski and Henry Woods. There have been many, many papers since that publication, with the intent to improve the understanding of the concept. Why write another paper on this subject?

The first reason is a shift in point of view from the pipe to the fluid. What information can we obtain from a simple balance of momentum of the fluid in bulk? For example, for flow inside a pipe, we can determine exactly the load exerted on the pipe by the flowing fluid in terms of only the fluid density, pressure, and momentum.

The second reason is fluid dynamics. Most effective force papers have dealt with static fluids. How are these static effects modified for a flowing fluid? Do we need to add a pressure gradient to the pipe buoyancy? How is fluid friction included in the pipe loading? How does fluid momentum affect the pipe? For curved pipes we might expect a centrifugal force term. The answers to these questions are often surprising, even counter-intuitive.

In this paper, the general equations for the balance of fluid momentum are then combined with the equilibrium equation for the pipe. The effective force then emerges as a natural combination of pipe force and fluid force terms. A number of numerical examples are calculated to illustrate the new concepts. For example, what is the magnitude of the lateral load generated by the flow of fluid inside a curved pipe? How important is the fluid momentum load?
Multiparameter Autodrilling Capabilities Provide Drilling/Economic Benefits
Authors: Florence Fred , Porche Michael , Thomas Randall , Fox Ryan
Published: March 2009

Recent field data have shown significant economic benefits are achievable when utilizing electronic autodrilling technology in conjunction with surface sensors, wellsite computers and data acquisition systems. An electronic autodrilling system was developed to provide steady-state weight at the drill bit and/or differential pressure across the motors to produce a higher quality wellbore and faster rate of penetration (ROP). Recent field applications demonstrated conclusively that the electronic autodriller not only improved control of drilling parameters such as weight on bit (WOB) and ROP, but also provided other favorable drilling attributes like controlled reaming. Longer bit runs and shorter rotating times were also observed. This study outlines the results of an advanced electronic autodriller's field application, reviews the history of various autodrilling systems, and compares and contrasts each design with respect to practical application and economic benefit.

While brake technology improvements historically have led advances in autodrilling development, recent progress in computers and programmable logic controllers (PLCs) have significantly increased the capability of automated drilling machines, culminating in multiparameter control algorithms that maximize drilling efficiency. More recently, signal processing capabilities and variable frequency drive (VFD) electronic control have been extended to allow modern digital control technologies to be combined with older band-brake type braking systems, enabling conventional drilling rigs to be equipped with a sophisticated level of control without brake replacement and the associated capital investment. The new electronic automatic drilling system, when combined with computing and data acquisition technology, optimized drilling by controlling the existing non-linear rig braking system while simultaneously examining multiple drilling parameters: WOB, ROP, differential pressure (also called delta P) and torque. Multiparameter control was proven demonstrably better than single parameter or manual control.
Advances in API/ISO Standard Grade Purified Poly-Anionic Cellulose (PAC) and Drilling Grade Xanthan Gum (XG) Test Procedure and Specifications Definition
Authors: Keith Morton E. , Andrea Balestrini , Ton Maas , Mac Seheult
Published: March 2009

This paper will describe the technical work performed to develop reliable and reproducible testing procedures for standard purified Polyanionic Cellulose Polymers (PAC) and Drilling Grade Xanthan Gum Polymers (XG) leading to the introduction of new specification in API 13 A/ISO 13500.

The absence of standard procedures and specifications for PAC and XG materials have created confusing interpretations of the quality and expected performance. This opened the way to adulteration, primarily with starches (in PAC) and guar gum (in XG). A survey made within the API organization identified the need of standard performance testing procedures and specifications for pure-grade PAC and XG materials as well as adopting a test to easily identify the presence of adulterants. Simple procedures have been developed to identify starch or guar gum presence and establish performance testing procedures.

Numerous round-robin tests have been performed to fine-tune the testing procedures and measure intra and inter-labs reproducibility. Only testing procedures providing results with an acceptable standard deviation have been approved.

A new set of specifications including the following were finally defined: –moisture content, fluid loss and viscosity (for PAC)–moisture content, particle size analysis and viscosity (for XG)

The final procedures and specifications for both PAC and XG will be published with the new revision of the API 13 A/ISO 13500 in January 2009.
Aggregate Stability and Erosion Response to Antecedent Water Content of a Loess Soil
Authors: Vermang J. , Demeyer V. , Cornelis W.M. , Gabriels D.
Published: March 2009

Soil erosion processes are affected by the erodibility of the soil and by the erosivity of the rain. The effects of rain characteristics and invariant soil properties such as texture and organic matter content on soil erosion processes are well documented. The effect of antecedent soil water content (θa) on aggregate breakdown, seal formation, and subsequent soil erosion is much more disputable, however, as opposing effects have been reported. We conducted lab experiments with a rainfall simulator on a Belgian silt loam soil. The objectives were to determine the effect of θa on seal formation, runoff, and soil loss and to evaluate its effect on an empirical sediment transport equation. Air‐dried soil aggregates were subjected to θa of 0.04 (air‐dry aggregates), 0.12, and 0.19 m3 m−3 No runoff occurred on the soils with the highest θa, highest total runoff values were observed for intermediate θa, while intermediate amounts of total runoff were observed for the air‐dry aggregates. Soil loss, however, showed a different trend: highest values were found for the lowest θa, intermediate values for the intermediate θa, and no soil loss for the highest θa We further observed that θa had no influence on the final runoff rates and on the final infiltration rate through the soil surface. In using a water discharge and stream power equation to predict sediment transport, the intercept and exponent of the regression equations were found to be lower for θa of 0.19 than 0.12 m3 m−3, indicating decreasing erodibility with increasing θa We therefore suggest including θa as an additional variable to assess soil erodibility in deterministic event‐based water erosion models.