bluuebunny/crossref_metadata_2025 huggingface dataset:
Lost Circulation Management in Naturally Fractured Reservoirs
Authors: Savari Sharath , Whitfill Donald L. , Walker Jonathan
Published: January 2016

Managing severe-to-total lost circulation can be especially challenging in naturally fractured formations. This situation becomes further complicated if it is a producing formation. Particulate lost circulation materials (LCM) have been used to manage lost circulation for many years. However, current LCMs are not efficient in terms of size and application methods to cure severe-to-total losses, such as highly fractured reservoirs.

In the present paper, a novel acid-soluble combination in the form of an engineered composite LCM solution (ECS) with a multi-modal particle size distribution (PSD) has the potential to manage severe-to-total loss circulation situations in naturally fractured reservoir formations. The multi-modal PSD and unique combination of particles will help manage any uncertainties in fracture sizes, and the larger particles present will aid in plugging large fractures. The results of a laboratory investigation will be presented, highlighting the potential benefits of this solution.

When managing severe-to-total losses in highly fractured reservoir formations, particulates alone may not be effective, thus the LCM should preferably be acid soluble. The combination of a large multi-modal PSD LCM containing a fibrous material along with platelet particles was designed as a candidate for dealing with these extreme losses. The solution developed is capable of plugging laboratory-simulated fracture sizes in the range of 5,000 μm. It was further demonstrated that supplementing with another larger LCM platelet materials enhanced its capability to seal 0.5 in. (12.5 mm) in the lab. A significant determination in the solution developed is up to 96% soluble in 15% HCl and organic acids. This paper will discuss in detail the product concentration, testing methodology, and results. In addition, the strategy to apply these materials in the field will be discussed.

The large PSD, acid-soluble LCM solution can help manage uncertainties in fracture sizes and allow for curing severe-to-total losses in naturally fractured reservoir formations.
Optimizing Multistage Hydraulic-Fracturing Design Based on 3D Continuum Damage Mechanics
Authors: Shen Xinpu , Standifird William , Evans Scott
Published: January 2016

The purpose of this work is to build a real three-dimensional (3D) method for optimizing the design of stage intervals in multistage hydraulic fracturing and design of horizontal well spacing in unconventional oil and gas resources. The method proposed in this paper uses continuum damage mechanics as its basis for modeling fractures and their propagation under stimulation injection. The volumetric density of cracks created by injection fluid is represented by a set of two scalar-damage variables. This method can provide a solution for fracture propagation in two horizontal directions. This solution is used for the optimized design of stage intervals for multistage hydraulic fracturing and for the optimized design for well spacing in parallel horizontal wells. The determination of optimized stage intervals considers the overlapping effect of two nearby stimulation stages. A validation example of a design for the hydraulic fracturing of a set of parallel horizontal wells in a tight-sand oil formation is presented. A 3D numerical model was built for this purpose. A numerical solution for the distribution of continuum damage variables under stimulation-injection loads is obtained with a poro-elastoplastic damage model by using the finite element method. The effective fracture length with the critical value of synthetic damage variable (DV) is determined. The optimized stage interval and well spacing are determined, respectively, with reference to numerical results of continuum damage distribution generated by stimulation. The critical value for the synthetic DV is the value of the DV that can represent the opening of an effective fracture. The distribution of synthetic DVs generated by stimulation injection was calculated and analyzed. The stage interval along the well trajectory and the well spacing are determined by using the numerical results of continuum damage distribution. This method can provide a fracture propagation solution in three directions of a 3D volume, which creates a real 3D method for fracturing analysis.
Multilateral TAML-4 and -5 Junctions Provide Consistent Results for Arabian Gulf Operator
Authors: Glaser Mark , Rosas Eulalio , Rivero Gilberto J
Published: January 2016

Since 1999, more than 120 wells in Saudi Arabia have been completed using multilateral technology (MLT). This paper will discuss case histories, associated technology improvements, and best practices in which dual-lateral completions, with and without pressure-isolated junctions (Technical Advancement of Multilaterals (TAML) levels 4 and 5), were developed and used to help ensure that each installation met the operator's objectives.

Advancements and improvements in multilateral technology has led to reduced risk and enhanced well production, while addressing the operator's well challenges of maximizing reservoir exposure and increasing the use of existing slots. This paper uses end-of-well and incident reports to identify areas for improvement, the subsequent implementation, and the results of system modifications. Focused planning of drilling operations, wellbore preparations, installation procedures, and development of contingency methods led to the success of the installations. The operator's commitment to using this technology has reduced non-productive time and provided incremental cost savings as process improvements were implemented over the 15-year period.

Multilateral technology in Arabian Gulf offshore fields has enhanced productivity using innovative techniques to fulfill the completion and intervention requirements of dual-lateral wells, with and without pressure-isolated junctions. Collaborative multidisciplinary teams comprised of engineers from the operator and multilateral service provider were assigned to help ensure the successful implementation of the technology. The system modification goals of improving consistency and enhancing the surface indications of downhole progress during the junction construction were met, thereby increasing the reliability and overall confidence in this technology. The multilateral systems were run in both new and existing wells, and the operator's objectives were met in each case. The successful implementation of this technology has expanded the use of multilateral completions in the Middle East.

This paper provides an overview of the evolution of advanced multilateral technology well-construction techniques and describes how overcoming challenges became a catalyst for innovation. This technology is now routinely applied to increase reservoir exposure and meet development and production goals.
Application of MWD Survey Corrections in Real Time
Authors: Marr Tyler , Schiermeier Pete
Published: January 2016

The application of measurement-while-drilling (MWD) survey corrections is a critical step to ensure that the required service level is met and that definitive surveys are accurate, secure, and delivered in real time. Over the complex life of a directional survey, it is critical that these corrections are applied in the correct sequence and that the final survey is delivered to the directional driller within a time frame that avoids delays for critical decisions.

Past methods of supplying survey corrections to the wellsite vary greatly in terms of both methodology and speed. Techniques that are commonly deployed include file transfer, email, and online file sharing. Although there are benefits of using these methods, each falls short in one or more areas; these areas can include speed, security, or accuracy. Because of the need for one or more specialists to analyze the data, large amounts of data are often imported and exported. This process is not only laborious, but can also introduce opportunities for error.

To overcome these challenges associated with supplying the survey corrections to the wellsite, a new survey correction platform and associated workflows were developed. The new platform takes advantage of modern advances in software development and infrastructure along with the lessons learned from previous generations of software. The use of the new survey correction platform and application enables a database-to-database solution that streamlines multiple areas of survey handling. These areas include the application of in-field referencing (IFR1), interpolated in-field referencing (IFR2), multi-station analysis (MSA), and MWD survey quality control. The most significant improvement, however, is the removal of manual survey entry and extraction from the survey processing database and field MWD database.

This paper outlines advancements made at multiple steps in the lifespan of a directional survey to increase the speed, reliability, and accuracy associated with supplying survey corrections to the wellsite. It also describes the applications of this process in a real-time environment.
MWCNT for Enhancing Mechanical Properties of Oil Well Cement for HPHT Applications
Authors: Khan W. A. , Rahman M. K. , Mahmoud M. A. , Sarmah P.
Published: January 2016

Growing demand to drill High Pressure High Temperature (HPHT) wells requires improved technology to overcome the HPHT challenges. Oil well cementing has a greater impact on the production potential of a well as compared to other operational actions. A successful cementing job is dependent on how quickly and efficiently cement achieves strength. Achieving desired mechanical properties of cement becomes harder and complex at HPHT conditions.

A wide variety of admixtures are commonly mixed with the oil well cement slurries to deal with the extensive range of pressure and temperature to acquire enhanced mechanical properties depending on the combination of admixture used. Carbon Nanotubes (CNT), declared as "Miracle Material", have been one of the most recent admixtures being used to achieve the desired mechanical properties of cement slurries. This paper highlights the study carried out to examine the mechanical properties comprising compressive strength of oil well cement slurries integrating chemical additives and CNT under high pressure high temperature (HPHT) conditions.

Three different percentages of functionalized multi-walled CNT's (MWCNT), at 0.1%, 0.25% and 0.5% bwoc, were mixed with Type-G oil well cement together with other additives used in HPHT applications. Compressive strength investigations (Destructive and UCA) were carried out on those slurries. SEM investigations were also conducted on selected MWCNT mixes. The study indicated that incorporation of MWCNT, at a very small percentage, in cement slurries resulted in a significant increase in the compressive strength values.
Case Study for Real Time Stick/Slip Mitigation to Improve Drilling Performance
Authors: Vogel Stephen K. , Creegan Andrew P.
Published: January 2016

Stick-slip oscillation is a recognized and documented drilling dysfunction that reduces drilling performance and increase well costs. Stick-slip is a drilling phenomenon associated with the use of fixed cutter bits that use a shear cutting mode and exacerbated by non-optimal weight on bit (WOB) and rotations per minute (RPM) settings. The bit speed can vary drastically from fully stopped to twice the RPM setting (0-200%) during periods of stick-slip oscillation. This case study details the benefits of an automated stick-slip identification and mitigation system and service using surface measurements for an Operator drilling in a geographically diverse area. The stick-slip mitigation service was successfully used to increase ROP, reduce the drilling time, and improve bit performance.

Traditional methods of reducing stick-slip include varying the WOB and RPM set points by the driller, which requires the driller to identify the stick-slip occurrences and manually manipulate both settings. Inefficiencies are inherent to this process as the driller is unable to accurately quantify the magnitude of the stick-slip period and set the optimal drilling parameters. Additional inefficiencies are associated with this method relative to how quickly the driller reacts to the onset of stick-slip and the frequency these changes are made while drilling.

An automated system was added to identify and quantify the stick-slip severity and to manipulate the top drive RPM speed to mitigate the stick-slip in real time. A real-time service complimented the automated system through the delivery of specialized training, remote settings maintenance, performance monitoring, and streamlining knowledge transfer.
A Case Study:Impact of Completion on Multi-Stage Fracturing Performance of a Horizontal Well in a Thin-Interbed Reservoir, Tarim Basin, China
Authors: Liu Huifeng , Yang Xiangtong , Yuan Xuefang , Liu Jiangyu , Chen Zhaowei , Tian Shouceng
Published: January 2016

Silurian reservoir in Ta-zhong Oilfield, western china, is a thin-interbed, low-permeability reservoir with buried depth from 4000 to 4500m. The sand distribution in this reservoir is heterogeneous both vertically and horizontally. Horizontal well with segregated completion and multi-stage fracturing is taken as an efficient technology to exploit this kind of reservoir. However, the existence of many mudstone interlayers makes the design of completion and fracturing difficult.

This paper will provide a case study on design and operation of multi-stage fracturing of a horizontal well in Ta-zhong Silurian reservoir. This well was fractured twice using two different technologies, firstly hydraulic jetting fracturing and then packer-segregated fracturing. Both the two operations encountered abnormal pumping pressure and sand out. The design and implementation process of both technologies will be introduced in this paper, and the challenges facing the completion and fracturing design will be highlighted. The causes to the abnormal pumping pressure and sand out will be analyzed comprehensively through numerical modeling and comparative calculation.

The results show that the defective completion design is the main cause of the failures of the two operations. For hydraulic jetting fracturing, the ill-considered jetting points and improper jetting space cause the difficulties for fracture initiation and propagation and therefore the sand out. For packer-segregated fracturing, the inappropriate perforating interval leads to simultaneous initiation of multiple fractures in each stage. These fractures interfere with each other during propagation, leading to great near-wellbore pressure loss and width reduction for each fracture, therefore the abnormal high pumping pressure and sand out were encountered. The acting mechanism of induced stress and fracture interaction and reorientation are illuminated in this paper. A bunch of ways to avoid these problems during multi-stage fracturing of a thin-interbed sandstone reservoir is also proposed from both designing aspect and operating aspect.

Nowadays, horizontal well with multi-stage fracturing is a common-used technique in tight thin-interbed formations. However, the design of a segregated completion and multi-stage fracturing is still a nodus for such formations. This paper gives a detailed introduction of a failure case and comprehensively analyzes the causes of these failures from geology to engineering, therefore gives a lesson for avoiding this kind of failures and optimizing a staged fracturing design in tight thin-interbed reservoirs.
Modern Jack-up Design Solutions for Mature Markets
Authors: Baan Rutger , Remco van der
Published: January 2016

In mature oil and gas fields particularly in the Middle East, India, Gulf of Mexico, West Africa and Asia, a specific footprint is required due to earlier campaigns. The key reference is the LeTourneau-116 design. With its specific footprint, it is the most widely used jack-up design in these regions. The CJ43 drilling jack-up, based on its successful predecessors, is the modern replacement and sets a new standard for jack-up drilling rigs used in mature oil and gas fields.

Drilling technology has evolved over the years. The focus has been on drilling equipment reliability, mechanization, partial automation and advanced well control. However, when reviewing the overall jack-up technology – excluding the drilling related equipment – a large part of what has been ordered recently resembles the same design philosophy of thirty to forty years ago. No significant changes on the jack-up design to improve its capabilities in terms of uptime, efficiency, material handling, maintenance, redundancy of critical systems and elements to improve human life on board.

But, when applying innovative technology, a more modern jack-up design such as the CJ43 can be shaped which delivers operational benefits to owners and operators in terms of lower OPEX and higher operational flexibility.
Friction Component of Tube Move Calculations in Unconventional Completion Design
Authors: Alexeyenko A. , Faraj O. , Adebiyi I. , Bernard Y.
Published: January 2016

Unconventional deep gas completions are subject to extreme hydraulic fracturing stimulation and production loads. These loads impose tough requirements on completion design. These completions must be capable of withstanding high compression, collapse, burst and tension loads.

Tube move calculation is a key part of Polished Bore Receptacle (PBR) completion design. Software simulation estimates compressional tube move due to the ballooning effect during frac operations, and the elongating tube move due to temperature expansion during production operations. With tube move estimated for all possible loads imposed on completion, selecting the right PBR length becomes possible. Current design practice is not accounting for Friction Factor (FF) in tube move calculations. This practice is acceptable for conventional gas wells completions with less tube movement where 20 ft. long PBR is adequate. When dealing with unconventional deep gas frac stimulated completions, this design approach leads to tube move requiring 30 ft. PBR or possibly longer. While the solution seems to be a simple replacement of the equipment, the impact can be huge including such issues as logistics, use of heavier completion fluid, higher slack off weight for landing upper completion and other possible, unforeseen complications.

Discussion with engineering software provider and scouting industry publications did not reveal the answer to why the use of FF is not a standard practice in software simulation of tube move. We had to find the answer ourselves, allocating drilling rig time and conducting a number of tube move measurements in actual unconventional completions. Using digital slick-line with gamma-ray (GR) and casing collar locator (CCL) logging tool the actual tube move caused by high-pressure ballooning effect was measured and the applicable friction factor was deduced. Applying friction component drastically reduces software simulated tube move and requirements in length of PBR, weight of completion fluid and slack-off weight for landing upper completion, thus simplifying the completion and reducing risks and cost.

The following paper discusses the measurement of tube move under actual well conditions and the resulting deductions on the effect of friction. Identified FF is recommended for use in optimized unconventional completion design.
Cluster Wells Applied in Wetland Environment in North Azadegan
Authors: Liu Bingshan , Wang Xi , Tu Apeng , Zhang Shunyuan , Jiang Zi , Fu Jin
Published: January 2016

Most area of North Azadegan oilfield is covered by wetland, especially, in the north part it is covered by reed marshland with 1.5-3m deep water. Meanwhile, there are lots of landmines left during the Iran-Iraq war. It is expensive to construct pads in this area (more than 300 million dollars for one pad). In order to protect environment, decrease dangers to construct pads and save cost on building pads, cluster well is the first choice.

In this paper, well network was optimized first based on geological requirements and environment limits. Formations upper 800m are unconsolidated, 800m-1000m mainly are shale and more stable, Gachsaran contains bout 1800m salt-gypsum in lower part with high formation pressure about 1.8g/cm3 and high pressure salt aquifer with EWD up to 2.31g/cm3. Two plans for kick off point of horizontal wells were considered, in the interval 800-1000m or below Gachsaran. Multi-well anti-collision and avoidance of obstacle were considered and the well profiles were optimized.

15 well pads for cluster wells were designed: 5 pads with 5 horizontal wells, 1 pad with 5 horizontal wells and 1 vertical well, 1 pad with 4 horizontal wells and 8 pads with 2 horizontal wells. This protects environment and saves cost expending on pads building to the maximum extent. After considering effects of KOP on dogleg and inclination and the downhole complications encountered in drilled wells comprehensively, kick off point was built in Gurpi formation about 2300m deep (below Gachsaran). Based on this, optimized the wellbore trajectory, BHA and parameters. By far, all the wells planed have been finished, there is no any collision accident, target hitting rate is 100%, drilling catching rate in reservoir is 100%, both the success rates of electric logging in horizontal interval and casing running in designed depth are 100%.

The drilling experience and expertise in north Azadegan oilfield could be used for a beneficial technical reference for drilling in such complicated environment and complicated formations.
Advancements in Well Conformance Technologies Used in a Major Field in Saudi Arabia: Case Histories
Authors: Al-Zain Ahmed , Al-Atwi Mohammed , Al-Jandal Ahmed , Al-Abdalmohsen Rami , Al-Ghafli Hashem
Published: January 2016

Water management practices are an integral part of effective well and reservoir management to avoid various water production problems. Water production problems are major challenges in the oil and gas industry. Many strategies have been used in the industry to control water production problems both in producers and injectors. There are many water control methods available in the industry, including mechanical and chemical methods; sometimes a combination of both methods is used.

With the advent of horizontal drilling technology, unique opportunities have been captured to enable efficient and effective water management. More complex wells of various types and shapes have been drilled and completed. The benefits of drilling these wells not only include reduction in development and operating costs because of the lower number of wells but also improvement in the reservoir performance and management of fluid movements. These complex wells are drilled for various and many objectives, which may include but are not limited to increased production, enhanced reservoir characterization, improved sweep, maximized recovery, and efficient reservoir management.

Water management practices implemented for effective water control, and to sustain oil production on two different areas in a major field are presented in this paper. One area exemplifies water management practices in a conventionally developed field, and the second area represents drilling conformance technology, utilizing smart MRC wells.
Integrated ERW Drilling Technologies for Weakly Consolidated Sandstone and Mudstone Formations
Authors: Fan Baitao , Zhang Xiaocheng , Xu Jie , Zhong Liguo , Yang Qiurong , Zhao Shaowei , Zang Ye , Chen Gang
Published: January 2016

There are many challenges in drilling extended reach well (ERW) for weakly consolidated sandstone and mudstone formations in Bohai Offshore Oilfield. For weak consolidated sandstone formations, it is difficult to control well trajectory, keep wellbore stable and decrease mud loss. For mudstone formations, the challenges include friction between wellbore and drilling tools, hydrating and swelling. At the same time, the measured well depth is larger than 3000 m, and the angle hold are larger than 70 degree. Additionally, the faults and the stress anomaly increase mud loss or complicate ERW drilling. Consequently, sticking of drilling tools or casing, and well collapse occur in past well drilling process.

In order to drill ERW successfully and safely in Bohai weakly consolidated sandstone and mudstone formations, integrated drilling technologies are introduced involving well trajectory design, drilling tool assembly, friction prediction and drilling parameters correction, adjustment of drilling mud, and casing floating and lubricating. The practical measures used include: (1) Different drilling technologies are employed in the deflecting section and hold angle section respectively; (2)Rotary steering-LWD tools are used in the second spud and the third spud; (3) Drilling parameters are corrected in-time according the real-time friction prediction result derived from drilling friction prediction; (4) Marine bentonite mud is used for layers over the oil formation to recover well cuttings rapidly and keep high drilling speed, and polymer enhance cation (PEC in short) drilling fluid are used while drill the oil formation to avoid sticking of drilling tools and protect formation; (5)Floating couplings and addition of lubricant are introduced in running protective casing to avoid sticking. Field testing show that above integrated ERW drilling technologies are practical for the sophisticated weakly consolidated sandstone and mudstone formations in Bohai Offshore Oilfield, and the drilling efficiency is significantly increased. The engineering design of the integrated ERW drilling technologies and field drilling cases are presented in this paper.
Acid Stimulation Studies on a Special Cement-Based Pill for Use in Weak Production Zones
Authors: Jandhyala Siva Rama , Patil Sandip , Songire Sumit , Singh Sheetal
Published: January 2016

The primary challenge with weak production zones is severe to total circulation loss resulting from natural fractures or low fracture pressures. A highly thixotropic engineered cement system has been used successfully in the field in several severe-to-total-loss treatment procedures involving weak nonproducing zones. This paper presents an investigation of this cement system's response to acid treatment and the possibilities of extending its use as a temporary plug to cure losses in weak production zones while helping minimize formation damage.

Tests were performed to understand the response of the highly thixotropic engineered cement system to acid treatment. These tests included acid immersion of cured cement cubes and exposure of set cement to a continuous supply of acid by exerting a differential pressure in an acid core flow apparatus. A reacted cement core forms a conductive path, resulting in a subsequent decrease in differential pressure or an increase in flow rate. Dependency on temperature and differential pressure were studied.

Experimental observations indicated that there was a formation of conductive path caused by a cement reaction when subjected to acid treatment. However, complete dissolution is a prolonged process and is unlikely to occur within the typical acid treatment times used in the field. If sufficient differential pressure is provided to allow the acid to diffuse through the entire volume of cement, a regain in permeability can be easily achieved, even with short exposure times. It has been observed that the time required to form a wormhole decreases as differential pressure increases. When acid was replaced with water, no wormhole formation or increases in the permeability of set cement occurred. This confirms that the wormhole formation is a result of the chemical reaction of cement with acid.

The study presented in this paper confirms that the engineered cement system is amenable for acid treatment. This provides opportunities to use this cement system to treat severe and total losses, as well as provide wellbore strengthening in production zones. Such an operation helps ensure that the production zone is well prepared for a successful primary cement treatment without compromising production.
A Novel System for Controlling Pore Pressure Transmission, Inhibition, Stabilization and Targeted Lubrication in Water-Sensitive Shales: Proof-of-Concept and Initial Field Results
Authors: Rea Anthony B. , Nagatani Ray , Davis Eric S. , Carlton Tim , Coragliotti Anna , Firliet Brian , Tran Sarah
Published: January 2016

Description of Proposed Paper

As the drilling industry has pursued more horizontal wells in water-reactive shales, the challenges from wellbore instability and high friction (e.g., stick slip, reduced Rate of Penetration [ROP], stuck pipe, severe doglegs) have led to increasing use of oil-based (OBM) and synthetic (SBM) muds. While costs associated with materials and waste-management for O/SBMs may make them more than twice as expensive as water-based muds (WBM), efforts to develop advanced WBMs that can broadly stabilize shale and lubricate have seen mixed results and limited applicability. To address these challenges, we have developed a novel methodology to control pore pressure transmission and reduce interfacial tension to rapidly and comprehensively deliver shale inhibitors within the near borehole shale pores while simultaneously targeting lubrication to high friction areas.

Application

Leveraging complex nano fluid technology as a chemical platform to convert water imbibition in shale pores into a pro-active tool dramatically reduces capillary pressures and focuses delivery of shale inhibitors within the near borehole shale pores. The combined features of reduced capillary pressure and inhibited clay platelets mitigate elevated pore pressure destabilization of the wellbore. As we have previously described, using polysaccharide-encapsulated oil targets lubrication to points of friction throughout the borehole strong enough to break the encapsulation. Laboratory and field observations indicate that these technologies can be used together to enable drilling with aqueous systems in water-reactive shale.

Results, Observations, and Conclusions

The use of these two technologies was associated with significant reduction (40 %+) in dynamic linear swell meter testing relative to incumbent aqueous shale stabilization technologies (e.g., KCl polymer) and a 76 – 91% reduction in coefficient of friction. In field testing, the technologies have been associated with keeping a wellbore stable for over 90 days (compared to an average of 12–14 days with KCl Polymer drilling fluid in the same field) and the reduction in drilling torque from 11 – 45 % in highly deviated wells.

Significance of Subject Matter

Results in the laboratory and field indicate that control of pore pressure transmission, objective inhibitor delivery and encapsulation of lubricant can be used in WBM to drill operationally and economically efficient in water-reactive shale. When employed throughout the build section of a highly deviated well the system can continue to be employed as a drill-in fluid because of its reservoir stimulation features4,6.
Optimum Mud Overbalance and ROP Limits for Managing Wellbore Stability in Horizontal Wells in a Carbonate Gas Reservoir
Authors: Khan Khaqan , Halim Abdul , Hamid Ab , Al-Anazi Hamoud A.
Published: January 2016

Saudi Aramco has been drilling horizontal and multilateral wells to develop gas fields. Due to production-induced decreasing reservoir pressures along with tight nature of the reservoir rock, development activities have focused more in placing wells towards the minimum horizontal stress direction and complete with multistage hydraulic fracturing aimed to improve lateral reservoir contact enabling higher production at sustained rates thereby increasing recovery with less number of wells to be drilled.

Horizontal wells drilled in the minimum horizontal stress direction are more challenging due to complex geological conditions and compressional in-situ stress conditions. The data shows that some wells were drilled without major difficulty while some other wells encountered more problems leading to stuck pipe events. A detailed study was conducted to identify the nature of these problems and ascertain major controlling factors for this variable drilling experience to make future operations safer and more efficient through recommendations based on a diagnostic analysis of the observed problems in existing wells.

Analysis of data suggests that excessive borehole breakouts and faster rate of penetration (ROP) are the key contributing factors to the observed drilling challenges. In addition, differential sticking has been found a potential risk across high porosity and/or depleted zones. As a result, optimum mud weight based on predrill geomechanics model was recommended to manage the hole stability. In addition, a safe limit of ROP as a function of hole azimuth was identified to manage efficient hole cleaning and avoid stuck pipe due to pack-off. The recommendations made based on this analysis enabled successful drilling and timely completion of several horizontal wells across the field.
Implementing the Pressurized Mud Cap Technique to Drilling through Total Loss Zones: A Way to Improve Well Control while Drilling the Reservoir in Oil Well Re-Entries
Authors: Al-Amri Khalifah , Guzman Julio C. , Al-Hashim Abdulrhman , Hassanen Ali M. , Moussa Ayoub H.
Published: January 2016

Drilling through total loss zones without returns at surface is a common practice for Operating Companies in the Middle East. This is known as the Mud Cap/Blind Drilling technique and it has been used for a long time in the region. The lessons learned throughout these years have produced well established procedures and "rules of thumb" for estimating mud density, volume and pumping schedule of the mud cap for different situations.

The application of this Mud Cap/Blind Drilling technique becomes more challenging when drilling through oil reservoirs with a high H2S content and combining zones with pressure regimes significantly different in the same hole section. This situation is often the case for some well designs commonly used to re-enter oil producer wells in Saudi Arabia. Under these circumstances, the main well control strategy is to maintain enough of a mud cap to prevent any migration of the hazardous gases and/or liquid hydrocarbons to the surface.

This approach often results in a conservative design of mud cap densities and volumes, which in turn generates huge expenditures in mud material and puts tremendous stress on logistics and transportation.

The Pressurized Mud Cap technique offers a safe alternative to Blind Drilling. This technique uses regular Managed Pressure Drilling (MPD) equipment to monitor the behavior of the reservoir at all times, improving the safety of the operation, by having accurate well control and realizing substantial cost savings, by optimizing the usage of drilling fluid materials and other resources associated with the mixing and pumping of the mud cap.

This paper describes the successful implementation of this technique for re-entering oil wells in an onshore field in Saudi Arabia. The paper also provides details for the equipment and procedures utilized to maintain a full column of fluid under pressure, by keeping the MPD choke fully closed while drilling without any returns at the surface. The results, when compared with the conventional Mud Cap/Blind Drilling Technique, show significant improvements in safety (well control), cost efficiency and logistics.
Optimized Drilling Approach, Yields Field Records through Very Hard Al Khalata Sandstone, in a Deep Gas Field, Oman
Authors: Roberts Tom , Djaoui Mehdi , Menezes Ruskin , Al-Bahri Salim , Vos Arjan , Hajje Mohammed
Published: January 2016

One of the main challenges drilling within the deep gas field "X" in Oman is the very hard and abrasive Al Khalata sandstone. The 8 3/8″ vertical section drilling performance is restricted due to abrasive wear and toughness of the polycrystalline diamond compact (PDC) cutter technology utilized, which limits both penetration and durability within the hard sandstone. Drill bit providers have typically tried heavy set drill bits to combat the early wear or damage to the cutting structure to gain performance improvements.

After an in-depth study of the application, engineers worked closely with a customer to fully understanding the true failure mechanisms through each lithology. Rock strength was analyzed along with a careful review of the current bit technology utilized. The team hypothesized that although the Al Khalata sandstone presented a cutting structure durability threat, the primary mode of PDC failure was thermal degradation and that simply trying heavier set drill bit designs to overcome this failure was not the solution.

Instead, the goal was to use a lighter set design to increase the penetration rate with improved point loading while fully engineering the PDC cutter to provide increased toughness and, more importantly, overcome the thermal degradation.

Al Khalata formation tests in Field "X" were completed after detailed laboratory testing that included cutter-rock interaction modelling to investigate the improved thermally stable PDC cutter. The initial field test utilized two 8 3/8 in. lighter set six-bladed designs equipped with the new thermally stable PDC cutter technology. Both designs successfully drilled the entire interval through the Al Khalata, Hasirah, Saih Nihyda, Ghudun, Lower Ghudun and Al Bashair formations. The result was a breakthrough in performance, setting a new interval field record including the longest 8 3/8 in. interval drilled in the Al Khalata with a PDC bit.

The results of this research led to new cutter and bit technologies which have proven that the combination of improved thermal resistance and more efficient cutter rock interaction will provide higher rate of penetration (ROP) for the section and demonstrate superior durability while drilling through the hardest stringers to complete the section. By focusing on the true failure mechanisms of the operation, the team was able to prove that improvements in cutter technology can yield breakthrough performance and in this case allow for a lighter set six-bladed design. The improved bit designs have repeatedly drilled further and faster than any previous attempts, resulting in significant cost savings for the operator.
An Integration of Drilling/Completion Technologies for Maximizing Long-Term Productivity
Authors: Lim J. C. , Cortes Pierre , Smith Lee
Published: January 2016

An effective approach for enhancing production and improving hydrocarbon recovery has been to integrate production engineering with drilling strategies to design well programs that optimize all aspects (hole sizes, casing sizes, well positions, etc.) for the long term exploitation of reserves.

This paper describes the use of such a multi-faceted approach in North Dakota Bakken wells and West Sak heavy oil sands in Alaska, both of which require long horizontal wellbores to be completed with multiple swell packers and/or liners. For maximum production, a smooth, well-conditioned, gauge hole is vitally important to enable the largest, most-effective and highest number of packers to be run.

Successfully getting liners to bottom so as to achieve optimum completions in these wells requires a repeatable process that is effective 100% of the time; therefore, requirements of both the drilling and production groups were combined in a strategy that integrates technologies specifically for improving the success of landing the liner on depth and helping drill a cost-effective, smooth, gauge hole.

In addition to the type of packer design / reamer/ centralizers / T&D equipment utilized, the paper describes how Torque & Drag (T&D) modeling in both the drilling and liner running intervals of these wells provided a number of strategic options for achieving a useable, quality wellbore that would facilitate running liner/packers into hole without damage. When these reaming while drilling techniques are used, excellent hole quality can be achieved without the need for dedicated clean out runs.

Demonstrating its effectiveness and applicability, this integrated approach has been employed on more than 100 wells to date, with more than 2 million feet of reamed hole alone, and more than 1,000 packers run on variety of wells, including runs in excess of 20,000 ft and laterals exceeding 10,000 ft in tri-lateral and penta-lateral wells.
Characterization of Boron-Based Nanomaterial Enhanced Additive in Water-Based Drilling Fluids: A study on Lubricity, Drag, ROP and Fluid Loss Improvement
Authors: Krishnan Shutesh , Abyat Zahra , Chok Calvin
Published: January 2016

The present work focuses on application of boron-based nanomaterial enhanced additive (PQCB) in water based mud system. The additive is specially formulated to improve friction, torque and hydraulic drag in challenging subterranean formations with bottom-hole temperature reaching 200°C. Extreme pressure tests were conducted using the standard 10 lb/gal and 13.5 lb/gal water based muds. For 10 lb/gal mud system addition of 5% of this additive gives torque reduction of 80% while for 13.5 lb/gal mud the torque reduction was 52%. We noticed an increase in rheology of the mud with the addition of this additive showing higher PV, YP and gel strength as compared to the commercially available lubricant. Low RPM rheology for high mud weight formulation showed a two-fold increase. Higher low RPM rheology will improve the drilling-hole cleaning and weighting materials suspension capability. PQCB also shows a consistent HPHT fluid loss control performance in 10 lb/gal and 13.5 lb/gal muds. This is due to its ability to withstand the higher conditioning temperature and prevent early breakdown of the polymers in the mud system. During a field trial in Myanmar at one of the wells with known hard subterranean formation, PQCB demonstrated an excellent performance with torque reduction of 36.36% and return permeability of 41% while the commercial lubricant gives torque reduction of approximately 13.64% and return permeability of 49%. Unlike any other ester based additives, PQCB shows no hydrolysis problem on both the mud systems tested. This enables the elimination of silicone and alcohol based de-foamers in the mud formulation. The nanomaterial enhanced PQCB additive is also biodegradable and helps to prevent the wear and tear of drilling tools that ultimately will reduce the overall production cost.
Managing Risks around Rigs Using Autonomous Marine Vehicles
Authors: Pai Sudhir
Published: January 2016

Obtaining accurate data is an important factor in drilling operations and can have lasting effects on exploration and production objectives. This abstract focuses on the use of autonomous marine vehicles (AMVs), a hybrid sea-surface and underwater vehicle that's capable of crossing thousands of kilometers of ocean to gather oceanographic data, for effective environmental seep surveys, taking meteorological readings while maintaining a stationary position, or circling a rig at a preset distance to provide early warning of security and environmental threats. Once deployed, it uses no crew, requires no fuel and produces no emissions, thus eliminating both risk to personnel and impact on the environment.

1Two AMV's were used to conduct a baseline survey offshore Northwest Australia. Quality data was acquired by the AMV's prior to commencing pipeline dredging work for the construction of two liquefied natural gas (LNG) trains and a domestic gas plant, 12 km west of Onslow on the Pilbara coast.

2A major operator used the AMV equipped with Acoustic Doppler Current Profilers (ADCPs) to aid in operations during a seismic survey in Gulf of Mexico. The AMV was deployed to measure current parameters, and to transmit this data in real-time via satellite to the seismic vessel as the survey was underway.

1The vehicles travelled a total of 1,424 miles over the 60-day mission, waypoint tracking remained stable and there was no lost survey time.

2This information helped the navigators to determine how closely the vessel could pass obstructions in order to minimize infill while at the same time avoiding entangling the streamer on the marine structure.

Both operations were completed in a cost-effective manner, and the vehicle replaced manned vessels, which were deployed for other important navigational challenges on the operation. The survey was optimized without compromising results due to the vehicle's ability to overcome a number of challenges including a significant dust storm which caused bio fouling, limiting data recording times, and a hurricane causing the vehicles to be piloted to a designated holding area. By utilizing AMVs, both operators were able to accurately estimate the uncertainties of a seismic survey, in a remote location in the presence of assets like rigs and process platforms where data was not readily available and to circumvent lost survey time during pipeline dredging operations.

This technology provides persistent ocean presence and a reliable data acquisition platform which can support numerous drilling applications. To date these vehicles have conducted 28 missions in the oil and gas industry with more than 3,100 days at sea. AMV's have proven to be a very cost-effective way to conduct exploration business while managing risks.
Successful Application of Innovative Engineering Approach to Reenter Problematic Reservoirs Leads to Astonishing Results: A Case Study
Authors: Al-Refai I. M. , Gratia P. I.
Published: January 2016

Objectives/Scope: Sidetrack drilling in depleted unconsolidated sandstone reservoirs with overlying reactive shale faces many engineering and operation challenges. Depleted reservoirs require a low mud weight to avoid stuck pipe due to differential sticking. Reactive unstable shale requires a higher mud weight to provide hole stability. Installing sand screens across the reservoir adds additional complication to drilling operations.

Proper planning is key to overcoming drilling challenges. Planning includes selection of well design, directional trajectory planning and mud selection. The selection of casing design depends on reservoir pressure and logging requirements. The requirement for a dual lateral completion also affects the hole configuration. The optimum kickoff point, maximum dog leg severity, inclination across the shale zone, shale footage and trajectory azimuth play important roles in the success of sidetracking operations. Mud weight and mud rheology are thoroughly planned and closely monitored during the operations. Drilling with a rotary steerable Bottom Hole Assembly (BHA) and deploying sand screen completion, such that it reduces chances of differential sticking, are also critical parts of the planning.

Many wells have been successfully sidetracked and completed to meet reservoir management objectives. The casing design of reentry wells has evolved from two (2) hole sections to one (1) hole section and has saved 32% of the drilling time and has reduced the well cost by 23%. Appropriate well direction (azimuth) and correct mud weight related to maximum or minimum stress direction have been identified utilizing special geomechanics software. The salinity of an oil-based mud (OBM) is critical while drilling through reactive shale. Water activity tests on shale samples is used to design the proper OBM and special monitoring protocols were established to ensure the rheology of the OBM. A modified sand screen completion has been proven to reduce the potential occurrence of stuck pipe.

Most of key factors in planning can be applied in all wells to some extent. Each well is uniquely based on its subsurface targets and reservoir pressure.