bluuebunny/crossref_metadata_2025 huggingface dataset:
How Much Does the Borehole Fluid Affect the Cement Impedance Measurement in Ultrasonic Scanner Tools?
Authors: Tello Lucio N. , Azuaje Dimas C. , Roberts Edwin K.
Published: June 2014

Ultrasonic scanner tools measure the cement acoustic impedance at higher radial and vertical resolution than standard cement bond and sector bond tools. The impedance is affected by variations of the borehole fluid contained in the well. This is not problematic for most wells as the tool is typically calibrated in the same fluid as the main logging section. Also, small variations in the well fluid between the bottom and the top of the logging section can go undetected in the computed cement impedance as these variations are continuous and not abrupt.

In the past, ultrasonic tools estimated the value of the fluid impedance by measuring the slowness and multiplying this value by the density. The fluid density is taken as a constant reading at the surface. Sometimes the slowness measurement is done during a logging down pass. An error is introduced when the fluid changes from one type to another because both slowness and density changes; however, density changes in larger percentages than slowness, causing the fluid impedance to have a substantially different value than the estimated one. This difference in fluid impedance causes the cement evaluation to be different also.

In the present paper we introduce a modified mud chamber for the ultrasonic radial scanner tool that measures the fluid impedance directly, in situ, while logging and with greater accuracy. In addition, we present an algorithm to compute the influence of changes in the cement impedance due to variations of the impedance in the fluid column. Laboratory tests are presented using static logs and logs obtained during field testing, corroborating the methodology and algorithm. Most of the time the tools give a correct reading but in instances where stratigraphic fluid columns with vastly different densities are present, if no correction is applied; it can mean the difference in detecting the presence or the absence of cement.
Impact of Formation Softening and Rock Mechanical Properties on Selection of Shale Stimulation Fluid: Laboratory Evaluation
Authors: Das Prasanta , Achalpurkar Manojkumar , Pal Omprakash
Published: June 2014

For low-permeability formations, such as oil- and gas-bearing shales, hydraulic fracturing stimulation is necessary to obtain commercial production. One of the key parameters for helping ensure successful stimulation and prolonged production is the proper selection of stimulation fluid. The selection and optimization of the fracturing fluid is greatly dependent on reservoir rock properties as well as formation softening attributed to fluid-formation interaction.

A slickwater treatment fluid has often been adopted in the past in tight shale plays for creating a complex fracture network for maximum production yield. Most often, the slickwater recipe is driven by formation fluid sensitivity analysis (e.g., effect of fresh water, salt, or acids on formation). While this might work for some formations, the rock mechanical properties, such as Young's modulus and Poisson's ratio, will determine the fracability and whether it is advantageous to use a slickwater, linear, or crosslinked gel. Similarly, analysis of formation softening using Brinell hardness testing and proppant embedment testing will help ensure the formation does not completely close on treatment completion and will have conductive flow channels. The formation rock, proppant, and fracturing fluid interaction can also result in diagenetic growth on proppant and formation faces, resulting in formation softening and large decrease in fracture conductivity. This paper describes test processes involving fluid sensitivity tests, formation softening, and rock mechanical tests, and compares data from a few representative shales to demonstrate the impact of choosing the proper fluid formulation for hydraulic fracturing.

This paper focusses on careful optimization of the stimulation fluid based on rock parameters to help ensure prolonged production in tight-oil and gas shale plays.
New Models for Reserve Estimation and Non-Darcy Gas Flow in Shale Gas Reservoirs
Authors: Haghshenas B.. , Clarkson C. R. , Chen S..
Published: June 2014

Organic-rich shale gas reservoirs have various complexities related to the physics of gas storage and transport. Traditionally, the OGIP in shales has been calculated as the sum of the adsorbed gas and the free gas, using CBM reservoirs as an analog. However, as recently noted in the literature, the free gas volume must be corrected for presence of adsorbed gas, assuming all gas storage occurs in kerogen. Even with these corrections in place, shales are still complex reservoirs in terms of flow characteristics. The contribution of viscous, diffusive, and slip forces in nano-scale conduits cause the permeability calculated from Darcy's Law to be higher than the value for liquids.

A new model is developed to address the effect of the adsorbed gas volume on the nanopore storage capacity. The relative fraction of adsorbed gas volume is treated as a sorbed-phase saturation. The initial free gas volume is then calculated by subtracting any non-free gas saturation from the effective void volume. We have extended this concept to a gas material balance equation through which the free gas volume is dynamically adjusted during depletion. The Simplified Local Density (SLD) adsorption model is used to evaluate sorbed-phase density and volume. To address the complexity in gas flow, permeability of the reservoir model is assumed to be a function of pressure in order to determine the impact of advection, slippage and diffusion mechanisms. The permeability is calculated via a multi-mechanism flow model. Finally, we utilized the dynamically-corrected permeability in parallel with dynamically-corrected porosity to simulate the primary recovery of a shale gas reservoir.

The new models successfully describe the unique characteristics of shale reservoirs and correct the conventional methods for overestimation of reserves and underestimation of permeability. The format of the final material balance equation and flow model used here preserves the conventional reservoir engineering framework, but with some important modifications.
New Before Closure Analysis Model for Unconventional Reservoirs
Authors: Lamei H.. , Soliman M. Y.
Published: June 2014

Minifrac/diagnostic fracture injection tests (DFITs) are an important and integral part of hydraulic fracture design and reservoir evaluation. Models for analysis of the before and after closure data have been developed. While several models exist and are being used to analyze the after closure data, before closure analysis (BCA) is not widely used, and only a handful of models have been developed. Additionally, the models are based on similar approaches and assumptions. This paper introduces a new BCA model based on rigorous treatment of the fluid flow equations in the fracture and the formation. In this new model, the assumptions of linear leakoff and short injection time for a minifrac test are made. In general, these assumptions are valid. In unconventional reservoirs, where permeability is expected to be very low, the assumption of linear leakoff is particularly valid and would last most of the duration of the before closure period. In most minifrac tests, the injection time is relatively small with respect to after shut-in time, which validates this new model assumption of short injection time. Fracture stiffness is a critical parameter when using this model, which can be easily calculated or measured from logging or experimental data. By using the before closure model presented here, formation permeability could be estimated by interpretation of the slope of straight line in the specialized Cartesian plot using before closure data.

This paper details the development of the new model and compares it to existing models. In addition, several field examples from unconventional formations are presented and analyzed using various techniques, demonstrating the applicability of this new model. The results are also compared to the after closure analysis (ACA).
An Optimal Approach to Shale Gas and Oil Exploration Beyond North America
Authors: Madhoo Hamechan A. , Acevedo Andres , Koley Manas , Bryant Ian , Laver Rod
Published: June 2014

Exploitation of shale plays is viewed by many as a major resource for future economies of many countries. To date, most exploitation of this resource has centered on North America where the existing high onshore well count previously drilled for conventional resources guides pursuit of unconventional plays.

The situation is, for example, very different across onshore Europe, which has a low existing well count for conventional resources and notable socio-political and infrastructure challenges, such as high-population densities. To be successful, the delineation of European shale plays must use existing data for exploration and drill a reduced number of wells during exploration.

During the exploration phase, the ability to manage uncertainty and make informed decisions across the potential shale plays is vital. An optimal approach is proposed, whereby all possible surface and subsurface sources of data are integrated and exploration screening is done based on advanced petroleum systems modeling. To illustrate the approach, data from onshore Netherlands has been selected. The West Netherlands Basin and Roer Valley Graben contain organic-rich Jurassic sequences within the Altena Group, including the well-known Posidonia Shale Formation. This formation is currently being targeted as a potential unconventional resource.

A fully integrated 3D geological model – including an advanced 3D petroleum systems model – is presented, which includes critical spatial information, such as geographical terrains and surface constraints. Results from this approach clearly demonstrate areas of higher prospectivity, and, importantly, their associated uncertainty. This allows E&P companies to select areas that have the best chance of success.
Influence Factors of Fracability in Nonmarine Shale
Authors: Fang Changliang , Amro Mohammed
Published: June 2014

Fracability, the capability of shale that can be fractured effectively, is the most critical evaluation parameters in shale gas production. At present, it is generally recognized that using mineral composition and rock mechanics parameters to represent shale fracability is difficult to fully reflect the comprehensive properties of shale in hydraulic fracturing. However, so far all fracturing research about shale gas is almost considering marine shale and the understanding of shale fracability is confined and trapped within marine shale. Since shallow deposit of sedimentary strata in China is non-marine (lacustrine) facies sediments, China pay increasing attention to non-marine shale, which is opposite to the situation in Europe, and with the deepening of shale gas exploration, Europe will focus more on the non-marine shale in following decades. Due to the fact that lacustrine shale deposits differ from marine deposits in sedimentary environment, the former are always with frequent sand and mud interbed, interlayers development. Therefore, the influence factors of fracability in non-marine shale seemed more complexes and the research of shale fracability becomes more significant.

After general contrastive study of sedimentary environment, gas generation, mineralogy and physical properties of non-marine and marine shale based on literature data, this paper separately analysed the fracability influence factors (including sedimentary environment, mineral composition, diagenesis, brittleness, nature fracture, etc.) of non-marine shale focused on the Mesozoic Triassic Yanchang Formation shale in Ordos Basin of China. Moreover, comprehensive consideration of all above influence factors and statement of some fracability evaluation methods have been implemented. Unified and quantitative evaluation of fracability influence factors in non-marine and marine shale has been discussed afterwards. The summary of main influence factors of fracability in non-marine shale not only improved the shale fracability research, but also could guide the hydraulic fracturing practice.
Integrated BHA System Drills Curve/Lateral in One Run at Record ROP Saving Seven Days Rig Time
Authors: Meli Ricardo , Salas Carlos , Martin Rodrigo , Roa Edwin Restrepo , Nervi Virginia , Zaheer Aamer , Durairajan Bala , Hill Richard
Published: June 2014

Abstract Rodrigo Martin

Apache Energia Argentina recently commenced horizontal drilling activity to develop shale gas reserves in Neuquén basin, Argentina. On the first well, the curve was drilled with a 12¼-in PDC bit on a positive displacement motor (PDM) bottom hole assembly. The lateral was drilled with an 8½" PDC on a point-the-bit rotary steerable system. A motor BHA was used in the curve because a standard RSS could not deliver the required dogleg severity (DLS). To optimize operations, the operator wanted to complete the curve and lateral with a single 8½" PDC bit. However, the lack of a high-build rate RSS tool required the curve to be drilled with a motor building to 50° of inclination then tripping for a point-the-bit RSS to TD the lateral. The single diameter strategy was successfully executed but further NPT reduction was still possible.

The challenge was to drill the curve and lateral with a high build-rate RSS and a single 8½" PDC in one run to eliminate a trip to change the directional drilling system. The introduction of an inclination hold and azimuth software system would enable the hybrid RSS tool, created to build the aggressive curve angle, to continue efficiently drilling in the lateral saving an additional trip. An engineering analysis was then launched to design an application specific PDC bit for the hybrid RSS. An FEA-based system was employed to analyze offset BHAs, directional profiles, bit technologies and mud properties. The study revealed that the baseline PDC was delivering excellent ROP in both the curve and lateral sections, but t modifications would be required to improve the bit's dynamic stability. A modified 8½-in SDi513bit was proposed that featured a customized cutting structure and gauge for improved stability.

Next, a rock strength analysis system was used to determine characteristics of lithologies encountered in the field. The study determined that Quintuco (curve) and Vaca Muerta (lateral) formations have relatively low unconfined compressive strengths (3-15 kpsi) but vibration potential in Quintuco formation is moderate. Computer simulations were run to map lateral/axial acceleration and bit torque on the hybrid RSS. The results showed that the new PDC design displayed a significant increase in dynamic stability compared to the baseline bit with similar high rate of penetration (ROP) potential.

The shale optimized BHA was run and it drilled 1289m of curve and lateral in one run at a record ROP of 9.64 m/hr, 35% faster than the offset average. The high build-rate hybrid RSS landed the wellbore at 96° inclination with a maximum turning radius of 11.8°/30m increasing reservoir exposure within the allotted acreage unit. The increased ROP enabled Apache to reach total depth (TD) seven days ahead of plan with savings of $595,000USD.
Intermixing of Cementing Fluids: Understanding Mud Displacement and Cement Placement
Authors: Chen Zhongming , Chaudhary Saleem , Shine Joe
Published: June 2014

Mud removal and cement placement during a cementing operation are key factors to ensuring zonal isolation. Actual well testing results show that majority of wells have zonal communication during the life of production. The communication between water and oil zones may significantly affect oil production and require expensive remedial squeeze treatments. Fully understanding the flow characteristics and interactive behaviors in mud, spacer, and cement is an important step to ensure critical zonal isolation.

A newly developed computational fluid dynamics model helps end users better understand the transport phenomena of intermixing multiple fluids. Fluid decay resulting from the intermixing involving the mud, spacer, and cement systems is quantified for given downhole conditions of wellbore geometry, fluid properties, pump rates and casing centralization. The robust method allows the analysis of potential hydrocarbon production zonal isolation success and optimization of cement placement. This advanced fluid displacement simulator has been field verified with impressive results for a wide range of annuli. A recently developed pseudo 3-D visualization module aids in understanding the complex phenomena as well.

Some field cases used for verification are included. The detailed job analysis demonstrates the methodology used to study the effects of fluid systems, pump rates, and centralization configurations and provides application engineers the opportunity to understand different scenarios while optimizing key parameters to achieve top tier results.
Evaluating Cost Efficiency of Rigless P&A for Subsea Multiwell Campaign
Authors: Moeinikia Fatemeh , Fjelde Kjell Kåre , Saasen Arild , Vrålstad Torbjørn , Arild Øystein
Published: June 2014

In a few years there will be a need for performing a considerable number of subsea plug and abandonment (P&A) on the Norwegian Continental Shelf (NCS). There are certain challenges associated with that such as more difficult access to subsea wells compared to ordinary platform wells, high daily rates of semi-submersible rigs and the fact that these rigs will be allocated for drilling new exploration and production wells to sustain the hydrocarbon production. For the moment there is large focus on looking for rigless technologies to decrease P&A cost and use of rig time. A probabilistic approach should be used to assess the cost and duration saving potential of such technologies relative to semi-submersible rigs.

In this paper, we will consider rigless technologies for performing parts of the P&A operation. For the first time, a risk based probabilistic approach including learning curves, correlations and possible risk events is used to evaluate subsea batch operated P&A.

A realistic example case which includes the use of a semi-submersible rig for batch operated P&A of subsea production wells is used to show how a probabilistic methodology can be implemented for obtaining probabilistic estimates of P&A cost and duration. Inclusion of learning curves and correlations makes the application of a probabilistic approach for multi-well campaigns challenging. It is demonstrated how to incorporate learning curves, correlations and possible risk events to capture a realistic range of cost and duration for multi-well P&A. In a second operational example, a light well intervention vessel is employed to accomplish preparatory work as well as wellhead cutting and removal for P&A of the subsea production wells in batch campaigns. These two case studies will be compared from a cost and duration point of view and it is shown that there are significant cost and duration savings related to transferring P&A activities from rigs to alternative intervention and vessel technologies.
HP/HT Exploration Well in Offshore Malaysia Pushed Automated MPD System to Maximum Utilization, Identifying Safest Drilling Operating Window
Authors: Rodriguez Freddy Rojas , Prasetia Andi Eka , Mettai Adel , Umar Lawrence , Thiam Yap Yun , Murad M. Syazwan
Published: June 2014

TTD-1 has been identified as the deepest HPHT well ever drilled by PCSB in Malaysia. Managed Pressure Drilling (MPD) enabled the Operator to drill and explore new sands and confirm new hydrocarbon reservoirs at 325 degrees F with an undisturbed bottom hole pore pressure of nearly 15,000 psi. The MPD technique in conjunction with the best HPHT practices was able to overcome challenges while drilling this exploration well. Challenges included:

Abnormal pressure ramp-up (greater than 17 psi/ft) High pore pressure steps in new sands Identifying and controlling wellbore breathing Controlling losses on the HPHT tight window zone

Technology and practices, including well control, HPHT drilling practices, pore pressure prediction and MPD, were integrated by the Operator during the planning and execution stages. The focus was to integrate MPD and HPHT procedures as well as optimize the available tools to maximize daily drilling footage and maintain the integrity of the well at all times. Annular friction losses (greater than 800 psi) were offset by Surface Back Pressure (SBP) to maintain constant bottomhole pressure (BHP) at all times, except instances when the annular backpressure was reduced for short periods to perform dynamic flow checks. Dynamic flow checks were performed every 45 feet measured depth to map the pore pressure. One of the dynamic flow checks identified one pressure step increase (greater than 1.0 ppg) and a 0.5 bbls gain on the trip tank at the same time. The dynamic formation integrity test (FIT) was successfully implemented to identify the upper limit of the operating window.

Proper application of these MPD procedures identified the minimum operating window as 1.0 ppg and guided the Operator to call for TD of the well. The well was drilled to a depth of 4,830 m, and thus penetrated vast gas bearing reservoirs. This technical paper aims to share a case study of HPHT drilling practices combined with Automated MPD successfully adopted to explore new sands with minimal offset geological and petrophysics information.
The Majnoon Field - A Case Study of Drilling Operations in a Remote Area of Iraq
Authors: Le Vesconte Marc-Jan , Tinkhof Rob , Hardman Paul
Published: June 2014

Iraq presents many challenges to international oil and gas producers. This paper will discuss one such operation, the giant Majnoon oilfield. The field was discovered in 1975. Following the drilling of 20 wells, operations were suspended due to the Iran-Iraq war of the 1980's. After the war, production resumed, however drilling did not re-commence until 2011.

The challenges of Majnoon are many: unexploded ordnance litters the field; (total) losses in the 12 ¼" hole; logistics require extensive planning and all drilling is undertaken by rigs with less experienced crews. Operator's tendering guidelines required a turnkey arrangement between Operator and the main Contractor, leading to an intricate arrangement of sub-contracts. Limited offset data further challenged the drilling process, with a steep learning curve evident across the field. With different disciplines on the critical path to meet the production target date, associated simultaneous operations led to rescheduling and flexibility on the part of the drilling operations team.

Major success factors include a focus on performance; contract management; having the ideal team in place from day one; upfront planning and competence assurance.

The paper will discuss aspects of the drilling program, from the initial contracting strategy, through to the final well delivery. Following an assessment of learning from the early wells in the sequence, the evolution of the performance culture will be discussed. The working relationship between the operator's field team and that of the main Contractor will be examined, particularly given the turnkey nature of the operation. The realignment of the project objectives after the first three wells will also be addressed.

The aim of the paper is to present a case study of the complexities that arise, from operating in a country recovering from a troubled period. The intent is to share learning that may enable future operations in Iraq to avoid some of the operational pitfalls seen in Majnoon.
Constructing Difficult Colony Wash Lateral with Innovative Rolling Cutter Technology Improves Drilling Performance
Authors: Bruton Greg , Smith Mark , Mueller Levi , Ford Robert , Bits Smith
Published: June 2014

Efficiently drilling the lateral hole section through the abrasive Granite Wash reservoir sands in western Oklahoma and the Texas Panhandle creates a unique challenge. The highly heterogeneous formation was causing inconsistent PDC bit performance while constructing the 6-1/8" horizontal and thus damaging project economics. A study determined that improved ROI could be achieved by extending bit life in areas where poor drilling performance is expected. A detailed forensic analysis showed extensive cutter damage with abrasive wear being the most common dull characteristic. The cutter wear was causing short runs and frequent trips for bit change-out. To solve the problem required a new approach.

A fixed PDC element creates an inherent limitation because only a small portion of the cutter contacts formation and as the cutter wears, drilling efficiency declines. The resulting wear flat generates a high degree of frictional heat which breaks the diamond-to-diamond bond leading to accelerated cutter degradation. The situation is exacerbated by difficulty transferring weight-on-bit due to extended length lateral drilling.

An R&D initiative was launched to investigate different methods to enable a PDC shearing element to fully rotate while drilling to increase overall cutting efficiency and bit life. Engineers investigated several different retention methods and developed a specialized fixed housing which is brazed into the bit blade. The PDC cutter is mounted on a circular shaft and fitted within the housing allowing 360° cutter rotation. The robust system holds the cutter/shaft assembly securely in the housing for superior reliability. The rolling cutter assembly has essentially the same OD as a standard PDC cutter for superior design flexibility and cutter placement options.

A new-style 6-1/8" PDC (MSiR613/MSiR713) was manufactured with rolling cutters strategically positioned in the shoulder area. It has been run over 45 times in the Granite Wash formation and is delivering positive results. On a steerable motor, the RC equipped bit has increased total footage, hours on bottom and ROP compared to direct offsets drilled with fixed cutter PDC.
Drillstring Network 2.0: An Enhanced Drillstring Network Based on 100 Wells of Experience
Authors: Pixton David , Craig Andrew
Published: June 2014

Wired drill pipe (WDP) has been used in over 100 wells worldwide to provide high-bandwidth communications between the surface and tools deployed in the wellbore. Such enhanced access to real-time data improves decision making, opens the door for advanced drilling processes such as automated drilling, and gives visibility to downhole conditions where never before possible.

WDP creates a high-speed drillstring network at the wellsite that operates independently of drilling fluid, enabling communications for the widest range of drilling applications and conditions. In addition, the network provides real-time memory/wireline-quality data not only from tools in the bottom hole assembly but also from tools that may be arrayed at intermediate points along the drillstring. These and other attributes of a drillstring network are compelling given the drilling challenges encountered in today's wells. Indeed, the numerous deployments in which wired drillpipe has been used have demonstrated that the network provides significant value to the drilling process in terms of drilling safety, efficiency and performance.

Learnings and experience gained across these operations have driven the development of a new and enhanced version of the drillstring network. This second generation high-speed drillstring network includes improvements to the design of wired drillpipe, a new generation of distributed network electronics, and a graphical surface network controller. These enhancements and their utility with respect to improving drilling processes are discussed here in detail.

These improvements are designed to create a more stable, robust and reliable network system. Further, the enhanced graphical surface controller expands network diagnostic capabilities and reduces the learning curve for network users. Revisions to the wired drillpipe design will result in lower cost of ownership and more cost-effective deployment of the technology, further improving the value the system can provide.
An Engineering Look at the Cause of the 2010 Macondo Blowout
Authors: Turley John A.
Published: June 2014

This paper examines engineering and operating activities during post-discovery temporary abandonment of the Macondo exploration well that led to and caused the 20 April 2010 blowout and oil spill in the Gulf of Mexico. The paper ignores finger pointing and hearsay evidence and focuses on data generated on the Deepwater Horizon drilling rig. The forensic trail defines events that caused and exacerbated a down-hole leak between the pay zone and the lower casing. Subsequent pressure testing of the wellbore revealed the leak, but the well was declared secure. In further preparation for temporary abandonment, seawater was pumped down a work string to displace heavy mud from the wellbore and riser. Such displacement caused the well to flow from the formation, down the annulus, up the casing, above the blowout preventers (BOP), into the riser, up to the rig, and over the derrick. Crews immediately closed two BOPs, albeit too late to stop the massive flow from within the mile-long riser. Subsequent explosions and fire killed eleven, sank the rig, and marked the beginning of one of the most lethal, costly, manmade, environmental disasters in US history. Had industry protocol been followed, and/or had the forensic data that pointed to the leak or flow been acted upon, the leak would have been repaired and isolated, the wellbore would have been retested to prove pressure security, and the temporary abandonment would have proceeded as planned.
One-Trip Chemistry Activates a Polymer and Cleans a Drilling Fluid Filter Cake at Once
Authors: Garza Ramon , Liu Bairu , Sadana Anil
Published: June 2014

An innovative sand control technology is being developed that has the capability to conform to the wellbore and apply a positive stress on the formation face. The technology is a porous shape memory polymer with the capability to change geometric shapes. This shape memory polymeric material is molded to an initial geometric shape. The material is then heated and compacted to a smaller volume, 25% of initial volume compacted, for run-in hole (RIH) geometry. As any shape memory polymer, it can recover its original shape if heated close to its Tg, or by temporarily chemically shifting its Tg to a new lower temperature that of its original Tg.

This paper will present the results of additives added to completion fluids, giving the final fluid composition the ability to activate the polymer to its original shape, and simultaneously clean up the filter cake left by the drilling fluid before the polymer reaches the wellbore. The additives are delayed so that the filter cake retains fluid loss properties during activation, but breaks shortly after the polymer reaches the gauge-hole, or has enough treatment caused by the one-trip fluid there by allowing for production at maximum flow rates. At the same time that the filter cake is being treated, a second additive is acting as a plasticizer on the shape memory polymer to activate it, forcing the polymer to recover its original shape. The results are measured via two test methods, one that monitors and records the activation time of the polymer to gauge hole, and a second method that measures the fluid loss properties of the filter cake ensuring that the filter cake is stable for the time required for the shape memory polymer to reach gauge hole.
Innovative Impregnated Drill Bit Design with Enhanced Durability Improves Performance in Challenging Application in Colombia
Authors: Becerra Fabian , Burch Connie , Cleboski Chris , Mendoza Sandro , Rodriguez Victor
Published: June 2014

Vertical wells are drilled in the Colombian foothills with various types of drill bits, including polycrystalline diamond compact bits (PDC), tungsten carbide insert bits (TCI), and impregnated (impreg) drill bits. With an operator's support a new 14¾-in. impreg bit was designed using an innovative new cutting structure to complete a challenging interval. This bit was paired with a low-speed power section and a high-speed power section in the bottomhole assembly (BHA) for two runs in the same well. Both runs did well, but the operator found the low-speed BHA to be a better match for the automated drilling system tool that was also in the BHA.

The multi-layered 14¾-in. section consists of hard and abrasive sandstone, interbedded claystone, and siltstone formations. The majority of drill bits suffer short runs due to severe wear in the outer region (shoulder) of the bit. The new impreg design was developed to increase run length and avoid unnecessary trips in the challenging formations.

The impreg bit uses diamond impregnated segments imbedded in blades comprised of diamond grit matrix material to create a cutting structure with variable wear along the bit face. This particular combination of diamond and matrix specifically corresponded to the application and improved overall aggressiveness and durability in the shoulder.

To drill efficiently, impregs are typically paired with high-speed motors or turbines (500-1200 rpm) due to the low depth of cut. This new impreg design, however, successfully drilled on two different BHAs. The first was with a high-speed power section (0.93 rev/gal) and drilled 108 ft at 4.9 ft/hr. The bit did not show signs of wear and was used on a second BHA with a low-speed power section (0.15 rev/gal) that drilled another 665 ft at 3.9 ft/hr. The impreg's overall performance was 773 ft drilled at 4.0 ft/hr. The bit showed only minor wear when compared to offset wells (15% vs. 80 to 100% cutting structure wear).

The addition of the impregnated segments and mixed grit combination improved the cutting structure durability. This success provides an opportunity to further develop the grit, matrix, and impregnated segment combination to increase the aggressiveness of the bit to drill faster and lower the overall drilling cost of a well.

This article will explain the benefits of the new technology and discuss how impregs effectively drilled hard and abrasive formations in a low-revolution application.
Directional Challenges and Planning of Relief Well to Resolve an HP/HT Well Blowout
Authors: Al-Muhailan M. , Al-Saleh Ali , Al-Shayji A. K. , Rajagopalan Arun , McKinnell D. C.
Published: June 2014

A blowout in an HPHT deep well posed a major challenge while designing the relief well which was required to bring the well under control. For the relief well it was necessary to carry out a comprehensive well design and operational planning, identification and mobilization of necessary equipment in a short time. This paper will describe the preparations made for this type of relief well in the region.

An existing deep J-shape directional well, suffered a blow out while drilling a deep Salt/Anhydrite formation where formation pressures were extremely high. The blowout well was surrounded with many other producing facilities, drilling activities and inhabited areas. The main challenge was to choose a suitable location as close as safely possible, in such a congested mature oil field, taking into consideration all the safety aspects such as wind direction, surrounded wells, flame and heat created from blowout well, etc. The other main well challenges concerned; well placement, intercept with blowing well and dynamic kill.

This paper will concentrate on the aspects of relief well design and planning. It will cover all related topics, such as; number of relief wells planned, surface location choice, potential drilling problems, directional design, detection of the blowout well, and placement philosophy. It will include a discussion on the specialized directional and ranging equipment and techniques needed to perform the critical operations of locating, following, and intersecting the blowing well. All aspects concerning HSE will be discussed in detail. The paper will present these in a case history format covering the design process, operational planning, and a description of well operations.
Innovative Drilling Systems for Kick-off, Curve Building and Landing a Lateral without Requiring Cement Plug
Authors: Swadi Shantanu , Desai Praful
Published: June 2014

Historically, the predominant sidetracking methodology for kick-off and subsequent curve building operation required setting a cement plug followed by using a directional BHA to drill deviated hole once the cement hardens. The success of the cement plug depends upon formation compressive strength, downhole temperature and pressure, wellbore deviation, cement plug depth, quality of cement and the plug cure time. The consequences of cement plug failure are extra trip time, a new cement plug, loss of drilling days and reconfiguration of drilling trajectory.

Recent R&D efforts have identified new methods and associated tools that can be effectively utilized to increase operational reliability in kicking off, subsequent curve building and landing a lateral without the cement plug in varieties of formations. This paper presents innovative drilling systems that can be deployed, azimuthally oriented, hydraulically set and configured to initiate drilling, all in the same trip downhole without the need for a cement plug.

The system includes:

A directional BHA which may include a rotary steerable system, a positive displacement motor or a turbo-drill A roller cone or a PDC or an impregnated drill bit selected for the formation with appropriate attachment mechanism A built-in deflector ramp for attachment with the drill bit and for maximum support and guidance to the directional drilling BHA A formation specific, expandable and hydraulically set anchor below the built-in deflector for three point firm grip with the hole wall to counteract rotational tendencies.

The increased reliability of the system comes from complete elimination of the cement plug and the ability to select appropriate drill bits and directional BHA for efficient kick-off and drilling a lateral. Additional benefit includes substantial cost savings in terms of reducing trip time and minimizing plugging materials.

The authors will describe the system's major components and the running procedure for different drilling situations. The authors will also discuss several field runs, involving various drilling conditions and utilizing different drilling systems. The field performance along with qualifying full scale laboratory tests demonstrates the system's viability and potential for operational reliability and cost savings.
Drilling Deepwater Carbonates Using Managed Pressure Drilling on a Dynamically Positioned Drillship
Authors: Ho R. , Moore D. , Pirie D. , Kozicz J.
Published: June 2014

Drilling carbonate formations presents challenging problems due to the high potential for massive loss circulation and well control situations. These problems can be further magnified in remote deepwater locations where access to material resources and logistics support is limited. Natural fractures commonly present in carbonate formations not only make losses and kicks more likely but they are also more difficult to control. The proper applications of Managed Pressure Drilling (MPD) methodology can help improve the safety of the drilling operations and greatly reduce the non-productive time associated with managing and solving the loss circulation problems.

The project discussed in this paper was executed in deepwater offshore Indonesia and clearly showed some of the benefits of using MPD in deepwater drilling. This paper discusses both the planning and execution of two wells drilled by applying various forms of MPD. The wells were drilled from a dynamically positioned (DP) drillship utilizing the world's first known application of a below tension ring Rotating Control Device (RCD), as well as an annular preventer for riser gas handling in between the riser slip joint and termination joint. Lessons learned associated with the installation of managed pressure drilling equipment on a DP vessel and the procedures used to drill the deepwater carbonate formations are presented in the paper.
Managing the HSE Interface: Changing How the Industry Owns the Space Where Operator, Driller and Service Providers Co-Exist
Authors: Hinton J. Jack , Debertrand M. Thierry , Karish John M. , Glencross Colette M.
Published: June 2014

"Great minds think alike" is a well known proverb that is often attributed to the results of successful actions. Within the oil and gas industry many individually possess the great minds and successful actions but at the well site, interface opportunities exist in how to maximize the synergies of our individual successful actions. Many of the catastrophic events within the industry have occurred in the physical and virtual space where Operators, Drilling Contractors (Drillers) and Service Providers co-exist. This may be related to where the joint parties have not effectively co-existed. While each has their own physical equipment and Health, Safety and Environment (HSE) Management Plans, these separate systems overlap. In this central space of overlap or interface, the risk of a catastrophic event can increase if the overlap is not effectively addressed or managed. Some collectively manage the interface using a Safety Case, Joint HSE Management Plans, and/or Simultaneous Operations Plans to identify hazards and mitigate risks. These processes and plans generally focus on addressing traditional Process Safety and Personal Safety hazards. Where the interface also jointly addresses the cultural and human factor aspects, by all parties, the risk of process and personal safety events can be greatly minimized.

This paper discusses the incorporation of the aspects of Culture and Human Factors into the management of the interface; complimenting the elements of Process Safety and Personal Safety. Five key aspects are explored: Mission, Accountability, Communication, Capacity, and Learning. By overlaying these aspects into a more holistic view of ownership, changes can be made to joint responsibility and management of this interface, enabling the industry to collectively accelerate step change in how process and personal safety risks are mitigated.
Don't Get Stung Setting Balanced Cement Plugs: A Look at Current Industry Practices for Placing Cement Plugs in a Wellbore Using a Stinger or Tail Pipe
Authors: Roye Justin , Pickett Sam
Published: June 2014

Cement plugs have been used for decades within the oil and gas industry. Some of the applications include zonal isolation, curing lost circulation, abandonment, and serving as a base for kicking-off or sidetracking. The most common method used for the placement of cement plugs is the balanced plug method using drillpipe, tubing, or a combination of both. The pipe is run in the wellbore to the desired depth of the bottom of the plug. A calculated volume of cement is placed in the well. Usually a volume of spacer is pumped ahead and behind the cement. When the plug is in place, the height of the cement and spacer left inside the pipe is the same as the height of the cement and spacer placed outside the pipe. With equalized column heights and fluid densities inside and outside the drillpipe, the hydrostatic pressure is balanced.

Tubing with a smaller diameter than the drillpipe is commonly run on the bottom of the drillpipe for setting a balanced plug; this smaller diameter tubing is commonly known as the stinger. Using a stinger lowers the height of the cement plug with the pipe in place, prior to pulling out of hole (POOH). The stinger also provides a larger annular cross-sectional area during cement placement. Some operators use a stinger with the assumption that it will minimize the disturbance of the plug while POOH, decreasing the chance of cement contamination.

If a stinger is used, the assumption that all fluids both inside and outside the drillpipe will remain in equilibrium is false. A mathematical analysis of what occurs once dynamic conditions begin by POOH with a small diameter stinger shows that the initially balanced system quickly becomes unbalanced. This analysis of placement technique can be valuable for any situation in which a balanced plug would normally be used for plug placement.

Perhaps the most critical component of most cement plugs, especially kickoff and sidetrack plugs, is compressive strength (CS) development. A cement kickoff plug with a final strength greater than the adjacent formation provides better support to sidetrack in the neighboring formation. Surfactant-laden spacers and drilling mud contamination have a drastic effect on cement CS development. The contamination of the cement plug with these fluids can result in failed strength development, which can result in failure to kick off the plug. The end result is lost time and money for the operator.
Rotating Casing Strings: Overview of Fatigue Assessment Methodology Based in Full Scale Lab Testing, and Application Cases Stories
Authors: Jordan Rodriguez G. , Grittini S. J. , Mazzaferro G. , Urdaneta E. D.
Published: June 2014

Casing and tubing are being increasingly used in drilling environments as an alternative to conventional drill pipe. Furthermore, OCTG tubular products are commonly rotated into place in horizontal and ERD wells. During drilling and running operations in deviated sections, the combination of the resultant bending of the string and its rotation generate alternating stresses in the pipe body and connections, creating the conditions for potential fatigue damage. Fatigue phenomenon could be related to cracks generation. The process includes different development phases until the failure of the component becomes evident; this failure could be produced at remote stress levels below the static elastic limit of the material. Since fatigue damage could lead to the failure of the string, which in general terms would predominantly occur on the connections, some considerations must be given to their resistance to cyclic loading conditions.

This paper describes the additional design considerations on top of standard design criteria for casing or tubing strings when subjected to cyclic loads, whether to select a suitable connection for a given application; to set a limit on operative parameters for a given application and connection; or to assess the fatigue damage suffered by a given connection undergoing a certain application. Comprehensive methodology applied for assessing fatigue damage introduced during rotating operations is proposed in this paper. It includes results of full scale laboratory testing carried out to quantify the fatigue limit of various semi-premium and premium connections, under different load conditions; statistical analysis methodology for developing robust fatigue life limit curves; and fatigue assessment methodology adopted for estimating fatigue damage introduced in real applications. The application of the methodology to some real cases is also presented in this paper.

The most significant outcome of this work is the possibility to reduce uncertainty related to casing strings mechanical integrity in rotating operations, such as drilling with casing, increasing chances of success.