Using the right drilling fluid with optimal rheology and filtration properties is one of the most important factors in successful drilling and completion operations. Designing the right drilling fluid depends on a variety of factors viz. formation lithology, wellbore geometry, temperature, pressure, and drilling objectives. To the best of the author's knowledge there is no standard drilling fluid advisory system to aid drilling engineers and scientists to formulate effective drilling fluids systems for the entire well sections. The paper describes a drilling fluid advisory system based on Artificial Bayesian Intelligence. The advisory system includes a Bayesian decision network (BDN) model that receives inputs and outputs recommendations based on Bayesian probability determinations. This advisory system has been designed to aid drilling engineers when designing drilling fluids for their operations. This paper describes a module that was created in this advisory system. This module was created based on several inputs viz. well geometry (vertical and horizontal), temperature, pressure, productivity. To create the drilling fluids module within the advisory system, a number of drilling fluid specialists/experts were interviewed to gather the information required to determine the best practices as a function of the above inputs. These best practices were then used to build decision trees that would allow the user to take an elementary data set and end up with a decision that honors the best practices. The designing process of this advisory system also included a number of standard lab tests that start from quality assurance, initial designing and finally using field samples to confirm the success of the application. The study also discusses several field cases that validate the drilling fluids advisory system. The novel drilling fluid advisory system based on Artificial Bayesian Intelligence has been designed to aid drilling engineers and scientists to formulate effective drilling fluids systems for the entire well sections.

Aiming to make the well planning process leaner and agile focusing on duration reduction without compromising quality of deliverables, automation opportunities have been identified within the multi-discipline iterations. The two key criteria considered for the selection of the automation project were: Minimum deployment effort and Maximum value added in efficiency. The initial project objective was to calculate formation tops for a well engineer without requiring the intervention of a geoscientist using commercial software. The methodology utilized is the following: 1. Inputs: Well trajectory and Surfaces. 2. Process: The algorithm finds intersections between surfaces and well trajectory. Surfaces and trajectory are represented as a set of XYZ points. To find the intersection, the software iterates through each point of the trajectory from the top, comparing the depth of the projection to the target surface. The projected depth to the surface is found by 2D interpolation of the surface. Once the trajectory point becomes deeper than the surface projection, the intersection is estimated using geometrical considerations of similar triangles. 3. Deliverables: Estimated formation tops for the given trajectory. 4. Results: Simple in-house developed software enhanced well planning workflow in an Offshore Green Field. The software converted to single executable file and can be run on any device without the open-source software installed. Very accurate results achieved with proposed algorithm with a negligible difference of 0.5 feet with the geoscience traditional software. Well planning duration reduced from average 1 week to 1 or 2 days. The workload for well engineers and the asset team has been dramatically reduced. Reduction of the number of commercial geoscience software licenses required. Way forward: A test with a slightly modified code was used to generate formation tops for more than 400 well in a Long-Term Field Development Plan project for a Brown Field during feasibility study. Upscale to all the Fields within the organization. Improve User Interface for better adoption. Include more formats for both, trajectories, and surfaces. Reduce computing time. This project represents the first initiative in the organization aiming to automate the well planning process. Overall, it represents the beginning of a journey where multiple opportunities for automation can be achieved using an open-source coding software that allows any engineer with little to no experience coding to being able to generate solutions to address daily challenges.

Two Schlumberger companies, Cameron and M-I SWACO, joined efforts to provide market with a drilling fluid optimization system to be used during drilling operations. Cameron delivers a complete remote-controlled and automatic drilling fluids mixing system, while M-I SWACO's technology facilitates continuous real-time measurement, analysis and optimization of mud properties. Today mud samples are measured every 6 hours or more frequently, depending on the conditions in the well. The properties are then adjusted for the most part manually, based on a mud engineer's practice. The Cameron Automix system comprises mechanized equipment and a robot for addition of chemicals into the drilling fluid, and works in concert with the M-I SWACO RheoProfiler instrument, which measures and analyzes drilling fluid properties in real time. Schlumberger (SLB) algorithms, designed to care for the known wellbore situations, automatically create optimal recipes for the chemicals to be mixed into the drilling fluid. The synergies between M-I SWACO's core competence in fluids and RheoProfiler technology and Cameron's competence in software and mixing equipment, result in a unique method / system of continuous stabilization and control of the wellbore through drilling fluid optimization. With the focus on a fully autonomous ‘closed-loop’ drilling rig, the spotlight is strongly directed on the drill floor activities and their automation. The main goal of SLB, in terms of automation and closed-loop activities, is to improve the primary well barrier, keep well conditions under control, and rig safe. A combination of each company's strengths, Automix and RheoProfiler can play an essential part in moving the drilling industry towards the same philosophy of fully automated and intelligent systems. The entire drilling operation needs to be viewed as one system, with one organization working towards a common goal, reducing exploration cost without compromising safety. However, there will always be a need for the mud engineer on board. Less visible in the general hype around automation and more efficient drilling operations, is the importance of optimized properties of the mud in the drilling process. Safety during drilling, better well bore, economy or producing reservoir are just a few of the benefits of the SLB solution.

Drilling a large directional hole section through the Middle East's hard carbonate formations using a polycrystalline diamond compact (PDC) bit and a rotary steerable system (RSS) bottomhole assembly (BHA) equipped with an expandable underreaming-while-drilling (UWD) tool presents a number of challenges. An operator was experiencing high-lateral vibration, stick/slip, and whirl-induced drilling dysfunctions, causing premature downhole tool fatigue failures. To reduce reaming runs and bit trips, a finite element analysis (FEA) -based dynamic simulation system was used to quantitatively analyze the complex interaction of various manufacturers’ downhole tools to optimize the BHA configuration and drilling parameters. Formation-related challenges were present in the carbonate formations, typically limestone and dolomite, known to be hard and interceded, along with the chances of well kick or complete losses, in addition to the shale formations, which are reactive as well as tectonically unstable. The shale formations tend to fall out if incorrect mud weight is applied. Also, the abrasive sandstone formations, comprised of interbedded shales, are reactive and mechanically unstable. The goal of the drilling operation was to effectively match the PDC and reamer cutting structures to minimize vibration. A modeling tool was used to define an optimized set of operating parameters for efficiently drilling the upper limestone, multiple limestone and dolomite transitions, and the difficult lower dolomite formation. The modeling enabled the drilling team to configure a BHA, which would efficiently deliver directional requirements in the curve and tangent as well as to mitigate potential push-pull issues in the critical transition zones. The BHA, run as modeled with the optimized operating parameters, produced good quality results. The six-blade PDC- RSS combination and underreamer BHA successfully drilled and opened the 12.25-in. × 13.5-in. wellbore with minimal lateral vibration and stick/slip. The BHA drilled 2,082 ft of wellbore, including the challenging hard and interbedded formations, which consisted of 6,000 to 25,000-psi limestone and shale with moderate- to high-impact indices at a 15 to 17-ft/hr average rate of penetration (ROP) and within authority for expenditure (AFE). The BHA delivered a high-quality, in-gauge borehole and efficiently delivered all directional objectives, building hole angle from vertical to 17.8° as required. The run was the first successful directional large-hole hard-rock UWD operation with a PDC-RSS BHA in Kuwait. The successful operation is the result of a proactive planned initiative to mitigate BHA shock loading, which included real-time monitoring using a predictive compressive-strength analysis system. The success also increased the confidence in the FEA-based modeling system's ability to accurately identify the root cause of damaging vibrations in the planning stage while underreaming the long sections of hard carbonates in the Middle East.

Casing running has historically been recognized as one of the most inefficient and dangerous processes on drilling rigs. Conventional methods carry with them a substantial equipment and personnel burden. This burden results in lengthy rig up/down times, a crowded rig floor and is often responsible for a variety of injuries and occasional fatalities. Recently, Casing Running Tools are being utilized that reduce equipment and personnel required on the rig, advancing the industry toward a safer, more efficient casing running process. Casing Running Tools greatly reduce the equipment needed to run casing by incorporating many functions into one tool. Less equipment utilizing more intuitive procedures reduces the amount of rig up and rig down time. Both hydraulic and mechanical tools are currently available to the industry. Hydraulically operated tools require a "Hydraulic Power Unit" (HPU) and an operator on the rig floor to control the CRT's operation. Mechanical tools are more compact, do not require HPU's and place complete control of the tool and the casing running in the hands of the onsite driller. For this reason, a mechanical tool was selected for this string. This paper will cover the results of the run in terms of tool efficiency, tool efficacy, safety, and TRS footprint. Tool efficiency will be compared between a mechanical casing running tool and conventional methods, in terms of rig-in times and run times. This will include considerations between efficiency at the beginning of a run and expected efficiency gains near the end of the run. Efficacy will be discussed in the context of the tool's ability to satisfy its desired function. This is less directly measured but will include input from rig personnel and measurable components such as connection reports. Arguably the most important benefit will be recognized in equipment and personnel requirements, and this paper will discuss the differences in conventional services and the use of a mechanical CRT using conventional services as the baseline for comparison. The discussion concludes with an outline of the benefits realized by the operator, service-company, and other rig personnel. This publication reviews the first application of a fully mechanical CRT in Kuwait to run a string of casing with premium threads. This is also the first 630-ton casing string run with a mechanical casing running tool in the Middle East Region. A newly developed wireless Torque Turn Sub that matches the hoist and torque capacity of the CRT was also used to monitor and record the torque on the premium threads.

As operators move towards intelligent wells and fields, data management systems need to be adapted to support the transformation. With technology advancements and a growing network of sensors that enable faster and higher frequency data gathering, there is a need to sustainably scale data management systems to the level required to handle higher volumes of data and faster processing response. The most comprehensive systems, however, are those that support efficient decision making. A Middle Eastern operator embarked on a project to enhance the existing well integrity data management system to add new capabilities and extend the system to other fields in the Arabian Gulf. The updated well integrity management standards were also incorporated to reflect the operator's latest business principles. The system was further integrated with a geographical information system and well integrity business workflows were developed. The system automatically monitors data and sends notifications on abnormal well conditions. This is being supported by a single repository of all necessary data, historical inspection, pressure trends and well intervention histories. Through continuous monitoring of operating conditions by the system and automatic task assignment when conditions indicate the rise of well problems, engineers can work more proactively and manage a growing number of assets. Automated monitoring relieves engineers from the efforts previously exerted on manual processes and allows them to focus on the engineering analysis. Having a single repository with historical inspection, safety critical equipment test data, full pressure trends and well intervention histories, provides a wealth of information from which to make informed decisions. A benefit of having such methodology, from a management viewpoint, is that there is a common approach to well integrity indicators and key performance indicators for all assets. This allows benchmarking from field to field so that a consistent decision making approach can be made and resources of different types properly focused on those places where the challenges and demands are higher. In a period where the industry has gone through some substantial rationalization, the fact that staff can be assigned to different assets through the use of a common system with which they are familiar helps them to quickly understand, analyze and tackle well problems. This paper examines the application of intelligent software analytics and a robust system to optimize resources and enhance efficiency and performance. By collecting a wider range of data with increased frequency and applying intelligent software analytics, the operator has been able to greatly improve the asset management coverage, thus improving efficiency and performance; satisfying regulatory requirements and achieving production targets.

Prior to undertaking any drilling campaign, the process of offset well analysis is of paramount importance. When performed accurately and presented properly it provides the basis for all design work and risk analysis. A new feature in the modelling software Petrel called Drilling Risk Manager offers the ability to be able to carry out the offset well analysis in a 3D environment. The aims of this study is to investigate the means in which the Drilling Risk Manager feature of Petrel can aid in de-risking wells during the offset well analysis process and to highlight the potential efficiency savings that can arise. The efficiency savings of using Petrel have been highlighted through the use of a case study focusing on the initial development work that was carried out in conjunction with TAQA for their North Cormorant and Cormorant East fields in the UK continental shelf. In this study a Schlumberger engineer worked closely with TAQA on classifying the offset well data for the field, populating the data into a 3D shared earth model in Petrel and then using this model to perform a full risk analysis. For TAQA, using Petrel has made it easier to clearly view all of the drilling hazards that have occurred on the North Cormorant and Cormorant East fields. Using all of the extra information, two wells drilled on the Cormorant East field were well prepared for hazards which are common in the area. Using the 3D model to aid in the risks analysis process saved a considerable amount of time in comparison to the usual method employed by TAQA. Schlumberger are in the process of fully developing the use of Petrel as a means of derisking wells in mature fields in to a value added service that can be provided throughout a drilling campaign. Projects are being developed for several UK Operators in this field, incorporating well bore stability and drilling analysis in order to provide efficiency savings throughout a drilling campaign.

The purpose of this paper is to show and increase understanding of the concept for competency assurance in order to encourage associations of drilling professionals (Applicable to any industry) so they can develop their own and to motivate Drilling personnel to participate in this program. The concept of this program (competency assurance system) is used and it's applicable and usefulness for all who's concerned with the main capital asst (people) of all the new Engineers joining Drilling Division. This paper illustrates the work carried out by the Competency Assurance Management System team within the manpower development division in developing a competence assurance framework for Well Engineering, Drilling Supervisor, Completion & Wireline Engineer, Drilling Chemical Fluids Engineer - applicable across All ADNOC Group and the way forward of implementation, monitoring and continuous following up. This type of Work (WE - DFW) extracted from job description and job requirements of all OPCO's through their representatives, Skill Pool Experts (SPE'S). This work established in order to meet the business needs of drilling industry within OPCO's and to be capable of being audited which just done this year - 2013 by OPCO'S SPE'S and continuously measured through an agreed defined system and pre-defined performance criteria. The final product of this effort is a formal training program supported by endorsed training records and formal accreditation, (Top Management) then implemented through experienced personal using well defined tools as tour, monthly and Bi Annually reviews and finally a quarterly meeting with Presidents/Vice Presidents. The Competency Assurance Management System will be well defined as process wise and explained through the paper. It will shown how this program guaranteed a competent engineers on site or in office to work with solid experience so they can deliver a high quality drilling wells in order to achieve the company current and future targets. Hopefully this type of work adds value to the whole community and supports the strategies of development and advancement and makes certain cure to the whole unemployment difficulties.

The growing Exploration & Production (E &P) industry has an increased requirement for experienced and qualified Drilling Engineers and Supervisors. The Abu Dhabi Company for Onshore Oil Operations (ADCO) has the additional difficulty that the United Arab Emirates (UAE), due to its small population, is even today dependent on expat staff and the general interest of young Emiratis in technical jobs in the oil and gas industry has been marginal. Traditionally, ADCO has either hired a) international, mature, and experienced drilling engineers and supervisors and allocated them to various teams, putting them straight to work or b) young graduates, who were sent through the Competence Assurance Management System (CAMS) program (2 – 3 years). The quality of the work delivered usually depended on the onsite training and guidance their bosses provided them. However, ADCO is aggressively expanding and doubling its rig fleet from 23 to 46 land rigs in the next 3 years to achieve the oil production increase from 1.4 to 1.8 m bpd, which results in increased substantial staff requirement. This paper will present ADCOs Drilling Division strategy of introducing a combination of in-house development and external certifications to attract more UAE nationals, integrate the new international staff, and cater to the specific needs of their new recruits and their respective job profiles. The role of the three in-house training modules (the CAMS Real Work Learning Academy for graduates, the Drilling Newcomers Academy for mature hires, and the TA Academy for technical assistants) as well as the as external certifications (SPE certification, Shell Round 1 &2 exam, Chartered Engineer, and MSc for Drilling Engineering and Design) is to ensure a constant career development of drilling engineers, drilling supervisors, and specialists, as well as specifically supporting Emirati nationals to gain an internationally recognized first class reputation. As the lecturers and trainers are sourced in-house the graduates and mature hires are immediately introduced to most of their future leaders and colleagues in a proactive and hands-on environment allowing them to also share their own experiences and become regardless of their level of experience or origin: "FARIIQ WAHAD – One Team".

Real-time centres have been valuable in the oil and gas industry since the rapid growth of their use in the late 1990s. Both service and operating companies have embraced the advantages of having field data available at any time during the operation and making such data accessible to many subject matter experts, regardless of their locations. Substantial improvements in service quality and operational efficiency have been achieved, proving the true value provided by these centers. But many of these centres were also built assuming they would become incubators of collaboration between the different teams that participate in both the design and execution of the well construction process. The benefits so widely observed for the execution phase are currently difficult to find reflected in added collaboration between the different stakeholders during well preplanning and design. The question arises if real-time centres can deliver on the promise of integration, or if they are tools to be used only during execution. This paper presents an implementation showing that there is still room for real-time centres to evolve. After developing a new method of managing and using real-time interventions, the subject centre captured information during the execution phase and made it available for collaborative planning sessions. The information was captured, stored, and consumed in such a way that all participating teams could use it to help make better decisions. This paper presents details on both the implementation of and early results for a center operating in Dubai and overseeing operations in Iraq that evolved into an Integrated Operations Centre (IOC).

One Page Program (OP 2 ) is a creative approach to save environment and time. Using the best available process and practices in our daily activities is one of our aims and core values towards the HSE in ADCO. Therefore, as a valuable step and part of our commitment, we have minimized consumption of papers by initiating OP 2 . Implementing (OP 2 ) upgrades the responsibilities of Drilling engineer to be in charge of other supportive operations such as; HSE, mud properties, cement slurry properties, direction drilling severities and reservoir rock and fluid properties and its characterization. OP 2 eliminates the repetitive work which has direct effect on time saving and maintaining the quality of the program. ADCO's Business Plan demands high number of wells to be delivered in development Fields for better reservoir sweeping efficiency such as; Infill drilling, injector's patterns and maintenance work-over operations in the end of each year. Also lately, for improving Drilling Division system organization, a life cycle engineer concept has been introduced; where two drilling engineers work back to back and each one is responsible for planning, well engineering and operations execution for every alternate well. Therefore drilling engineer has to maximize his effort and utilize his time efficiently in order to produce multiple drilling programs with excellent quality at the same time. The (OP 2 ) idea evolved and thought to be useful for the standard wells which have 90 % contribution to the business plan. This paper will take you through the process and steps in how it was evolved. Also the challenges faced between the field asset teams in formatting & generating the OP 2 . In addition to that the approval process and signature flow of OP 2 .

The 6"hole section in Raageshwari Field NW India (onshore) is typically between 600–800m long and highly challenging in terms of formation strength and abrasiveness. Lithology in the upper part is composed of sandstone, claystone and weathered basalt with unconfined compressive strength (UCS) between 3–5kpsi. The lower section contains basalt, felsic and sub-felsic igneous formations with UCS range of 15–30kpsi. Historically, a two bit strategy was employed. First, a PDC bit on a positive displacement motor (PDM) bottom hole assembly was used to drill the soft 6" section until ROP dropped to an unacceptable level. The BHA was then pulled and followed by a diamond impregnated bit on a turbine BHA to drill the very hard volcanics. Typical average on-bottom ROP for the entire section was 4.5m/hr and took approximately 170 hours to reach total depth (TD). To reduce costs, new technology was proposed to improve bit durability in the hard/abrasive volcanics and drill the entire 6" section in one run at a higher ROP. Recent bit and drilling data from offset wells was analyzed to assist in developing a new, cost effective PDC design to replace the expensive diamond-impregnated bits and drill the 6" hole section in one run. The study resulted in a new six-bladed PDC bit with 13 mm cutters that incorporates superior cutter technology to improve durability and resist physical and thermal degradation. The design includes a row of backup cutters in the shoulder area to increase radial diamond volume for maximum durability. The new PDC bits have been run on a motor and rotary steerable bottom hole assemblies and drilled the 6" section on three consecutive wells in Raageshwari field totaling 2328meters with an average ROP of 10.7m/hr. This represents approx. 47% decrease in drilling time compared to that previously achieved by Impreg/TCI bit runs. Typically, the new bits are pulled in re-runable condition. This improved performance has saved the operator approximately six-days of rig time and approximately USD 480,000/well.

ADCO's Business Plan demands a high number of wells to be delivered in development Fields for better reservoir sweeping efficiency such as: Infill drilling, injector's patterns and maintenance work-over operations in the end of each year, that result in increase of 50% of rigs fleet to meet the DWS (Drilling work over schedule) requirements in the next 5 years because the expansion in production will be from 1.4 MM bpd to 1.8 MM bpd. The rig move is an important component in the DWS as the average rig move between the wells is 4.6 days which in total 110 days and that is our driver to minimize the time consumed in rig move and gain more days for BP This Presentation will develop a study case for rig move optimization in BAB and ASAB Fields. In general two possible operation to move rigs are followed in our company: Mast-Up when the road allow us to do that, or conventional movement Mast-Down, if there are any obstacle in the way, like power lines, conductor lines or limited spaces (these movement requires additional time for laying down and rigging up the mast). The main idea of this study was to analyze the wells planned for BAB and ASAB fields individually for the next year and assign the rigs in order to avoid the movements Mast-Down, additionally trying to minimize the distance for the movement of the rigs and to accelerate the movement. Keeping this in mind the first step was plot all the wells planned in the original schedule and try to find nearest locations in reasonable time sequence, reassigning wells between rigs, also noting the power lines and pipes already in place, minimizing the crossing of these. Subsequently a review of the initial scenario and the proposed one was issued and all the possible savings in time and money were calculated. We found savings in ASAB field estimated in 60 days and 8 MM $, for BAB field the savings are 390 day and 19 MM $

Iraq is taking a radically fresh approach towards developing local talent. Instead of setting high quotas for employing local staff, Iraq has established a mandatory annual investment through a Training, Technology Transfer and Scholarship Fund (TTTSF) as a condition of awarding oil and gas contracts. This money targets building broader Iraqi capability in the industry as opposed to an individual company's staff. This approach overcomes the economic struggle between early project spending versus developing the essential local skillpool required for sustained project success - essentially fuelling the talent-engine at the start of the season. Shell Iraq Petroleum Development (SIPD) is paving the way by committing a portion of its annual TTTSF investment towards rolling out the first part of its Wells graduate training programme in its Majnoon operation in Southern Iraq. Dedicated recruitment and training staff are developing local Iraqi talent through a two-year programme culminating in a standardised assessment by Shell's Learning and Development team in The Netherlands. A pilot programme was started in February 2012 and the programme has been extremely successful to date. A second intake started in October 2012 and futher intakes are planned for 2013 and 2014. This programme builds industry capacity in Iraq and is the key to SIPD's Wells succession plan. If a similar approach to early development of local talent were replicated across the industry in Iraq, it stands to revolutionise Iraq as a regional talent hub. This paper outlines the main challenges faced in rolling out a structured Wells graduate training programme in the early development of the Majnoon field and describes how the challenges were overcome. An overview of the progam's success to date, current status and a forward-looking summary of the SIPD Wells Team's Iraqisation effort is presented.

Drilling the 16" hole section through mostly carbonates in southern Kuwait presents several distinctive challenges. Interbedded formations with vastly different compressive strengths that vary between 5-30 Kpsi and a significant amount of blind drilling can result in twist-off and lost-in-hole situations. The most common tungsten carbide insert (TCI) rollercone bit failures mechanisms are impact induced cutting structure damage, hydraulic inefficiency issues and bearing failure caused by high weight-on-bit (WOB) through the hard Dammam to Ahmadi carbonate sections. To solve the challenges the operator's drilling team, working in conjunction with the bit supplier, launched a performance improvement initiative. The carbonate application was analyzed using finite element analysis (FEA) based dynamic simulation program to fully understand how to stabilize the bit in different downhole conditions and improve hydraulic efficiency. Based on the computer analysis and field run data, engineers conceived a new stable bit design. The technology platform includes improved hydraulics and a specialized cutter structure configuration with tougher insert carbide grades to mitigate impact damage. A high-aspect ratio seal employs two dynamic sealing surfaces (ID, OD) that reduces frictional heat and minimizes wear to improve bearing reliability. The new rollercone bit was run with an optimized drilling plan with outstanding results establishing a performance step change in southern Kuwait's carbonate applications. The bit recently set a new 16" world cumulative TCI footage record of 12,656ft drilling three wells shoe to total depth (TD) and 531ft of a fourth well. The bit amassed a total 446 hours of on-bottom drilling time turning 2.4 million revolutions without a seal failure. The bit saved the operator 4.5 days of rig time plus bit spend. The new technology has enabled the operator to drill long footage intervals or multiple wells using a single bit with good penetration rates (ROP). The authors will discuss the formation challenges, application analysis and resulting performance improvement.

Introduction For multiple well drilling and completion campaigns, cost and schedule performance tend to improve over time. This trend in improvement is commonly referred to as a "learning curve." When a learning curve is assumed, the campaign cost and schedule estimates may be reduced dramatically (relative to an assumption of constant performance). Many operators consider the use of learning curves a best practice, and provide procedures for estimation and implementation in their cost estimating guidelines. This paper investigates methods for systematic integration of learning curves in probabilistic estimates. Brief reviews of probabilistic estimating methods and learning curves are provided. A general method and specific procedures for integrating learning curves in probabilistic estimates are then provided. For each method, the key assumptions are itemized and discussed and a demonstration is provided. While no single procedure will fit every situation, it is concluded that the general method is straightforward, transparent, and can be implemented using off-the-shelf spreadsheet software. The proposed procedures generate results that provide engineers and decision-makers with a refined representation of uncertainty, and can improve capital investment valuation and decision-making. Probabilistic Analysis The drilling engineering community is familiar with probabilistic analysis in well construction estimating, and in some drilling organizations, probabilistic estimating is a required practice. There are numerous papers on the subject. Murtha (1997), Williamson, Sawaryn, and Morrison (2004), and Akins, Abell, and Diggins (2005), focus on theory, methods, and implementation. Examples of empirical investigations can be found in Peterson, Murtha, and Schneider (1993), Peterson, Murtha, and Roberts (1995), Kitchel et al. (1997), Zoller, Graulier, and Paterson (2003), Hariharan, Judge, and Nguyen (2006), and Adams, Gibson, and Smith (2009). Conventional Methods. The conventional approach for probabilistic analysis is to first define a dependent variable of interest (typically a cost or time metric). The dependent variable is specified based on the purpose of the estimate, and estimates can be made for specific well activities, for an entire well interval, or for a whole well. Second, independent variables are specified as random variables based on an analysis of past performance. Third, the independent variables are sampled in a repetitive fashion and then used to develop simulated observations on the dependent variable. For example, the engineer may specify the rate of penetration (ROP) as a random variable, and then use a simulated result for ROP and the footage for a specific interval to compute interval drilling time. The procedure yields a simulated distribution of possible outcomes. The distribution of outcomes provides the engineer and other decision-makers with information not available from a deterministic estimate. In some decision settings, the range of outcomes can be more important than the expected value of the distribution. The main challenges in implementing probabilistic analysis are data collection and specification of the independent variable probability distributions (shapes and parameters). Several of the aforementioned papers address this issue and provide guidance. There are also other hurdles to implementation of probabilistic analysis. A survey of the global drilling community conducted in 2004 and summarized in Hariharan, Judge, and Nguyen (2006) indicated that a large majority of respondents believed that probabilistic analysis has value. But the survey also revealed that respondents felt the analysis took more time, that support tools were lacking, and that additional training was required. If the use of probabilistic analysis is to increase, it is important that workflows and methods remain simple in structure, easy to use, and transparent regarding the assumptions. One means to address these concerns is to perform the analysis using desktop spreadsheet tools. The advantage of this approach is that all of the assumptions and computations are transparent and subject to review and discussion.

Abstract This paper presents the development of a new bottomhole assembly (BHA) program and how it is used to deliver optimal BHA design. The new program allows users to run static and dynamic models in the same application which will save time and minimize errors. For the static model, the program uses the newly developed generic algorithm for solving the Lubinski's BHA equations directly. The strengths of the new algorithm are accuracy and computation efficiency, as compared to the conventional finite-element based BHA programs. In addition, the program is designed to run fast on a personal computer (PC) with an intuitive user interface so that it can be used to optimize BHA design in the office as well as at the rig site. The static model is primarily designed for directional drilling applications, such as optimal BHA design for maximum steerability, bending moment calculations to minimize fatigue failure, and BHA sag corrections to improve survey quality. The dynamic model is based on a hybrid of analytical and finite-element methods to calculate the critical rotary speeds of the BHA. This paper describes the significance of applying these features in a user-friendly application to improve the optimization process and maximize drilling performance. Introduction Bottomhole assembly (BHA) modeling is always an essential component of directional drilling. A state-of-the-art BHA program enables many critical features, such as designing a BHA to optimize directional performance, optimizing stabilizer locations to minimize vibration and increase downhole tool reliability, and improving survey data by correcting the BHA sag. Since the 1950s, several methods have been developed and applied in the drilling industry to build the BHA models. 1–7 In general, the challenges encountered in the development of a computationally efficient, flexible, and accurate BHA model can be summarized as follows: Nonlinear differential equations Unknown upper boundary conditions at the tangential point (location and orientation) Unknown boundary conditions at stabilizers Collars and wellbore wall contacts Large deformation caused by bent housing motor or the bend in rotary steerable tools The most commonly used method in BHA modeling is probably the finite-element method because it is easy to develop and use. However, to the knowledge of the author, many commercial finite-element based BHA programs are still based on the small deformation theory. As a result, they have been shown to lack the accuracy required to model steerable assemblies, such as motor or rotary steerable systems. Finite element modeling is also cumbersome in handling the collars and wellbore contact. To accurately model steerable systems, the semi-analytical methods are usually required, but semianalytical methods are inflexible and difficult to program. They are often designed to analyze some specific BHA models and are limited to BHAs with rather simple configurations. Objectives In addition to the challenges in finding an accurate and flexible static BHA model, most of the programs are cumbersome to run because of the complicated user interface or the lengthy calculation time. Thus, the objectives of developing a state-of-the-art BHA program include the following: Accuracy . It should provide the most accurate modeling results possible, especially for the motors and rotary steerable systems in which conventional finite-element based programs fail. Flexibility. The new BHA program should be capable of modeling any BHA configuration without restriction, as well as of handling the collar and wellbore contacts. The program should also allow users to model special drilling tools, if needed. Computational efficiency. The program will primarily be used on laptop computers by engineers. The computational time should be less than a few seconds for the most complex BHA model.

Abstract The Umm Gudair (UG) Field is located in West Kuwait and is managed by Kuwait Oil Company (KOC). With the aim of draining oil from the undrained northern flank of the west UG area, KOC decided to drill UG-132H, an openhole horizontal producer. UG-132H was chosen as the replacement well for an abandoned well. Located in the northern flank of the field, UG-132H was placed approximately 450 m west of the abandoned well. The lateral drain hole objective of keeping the well at a minimum of 65 ft above the oil/water contact was achieved. Executing this strategic well required careful selection of casing programs, drilling tools, services, and teamwork from all departments to keep the well within the desired target. To achieve the objectives, the KOC team decided to utilize an advanced proprietary rotary steerable system, logging while drilling (LWD) Imaging technology and the geosteering services to properly place the well within the reservoir. The steerable System enabled smooth and timely drilling of the drain hole. This resulted in a smooth and in-gauge borehole, hence producing a favourable environment for acquiring good quality real-time images for accurate structural dip determination and well placement. This paper will focus on the well profile, and the benefits of the advanced rotary steerable system for the long drain hole section. It will also highlight the complementary nature of transmitting both the density image and resistivity image in real time to enable accurate steering decisions. It will also show how the LWD images were useful in characterizing the different facies within the reservoir. Introduction Advances over the years in planning and executing horizontal wells has culminated with technical experts all over the world devising various means of achieving their goals. First of all, the technological advancement in seismic acquisition has enabled geologists and geophysicists to understand their reservoir structures better. They can now estimate the dips of the structure a lot better than before: also, the seismic data is continuously modified as more wells are drilled in the field. Depending on the complexity of the structure and the availability of control points, strategies are designed to tap from the vast hydrocarbon resources we have underground. Strategies may include using offset log data to create a model along the planned trajectory and thereafter matching data measured while drilling to the model to analyze the well position structurally. This correlation method lacks directionality of encountered bed and may sometime lead to confusion in deciding which direction to geosteer the well. On the other hand, advancement in LWD Imaging technology and the Measurements While Drilling (MWD) transmission rates has enabled resistivity-based or density- based images to be transmitted to surface to aid in deciding directionality of encountered beds and estimating dips of bed layers in real time. This is useful information in deciding what instructions to give to the drilling crew to keep the well within the reservoir.

Abstract Worldwide the costs associated with the exploration and production of oil have increased at a nearly exponential rate. This sharp rise in daily costs has also led to a new urgency from operators to find more reliable and efficient ways of doing business. Shock and vibration (S&V) are the leading cause of failure for measurements-while-drilling (MWD) and rotary steerable systems (RSS) today. These failures have a major impact on operators and service companies, costing millions of dollars in repairs and hours of rig time. A wide variety of service companies now offer lateral, axial, and transverse shock measurements, as well as downhole revolution per minute (RPM) readings to better understand downhole dynamics. These measurements in the best of cases offer a reactive method of drilling, and at the worst provide no help in solving the problem or preventing damages to the bottom hole assembly (BHA). For shock and vibration measurements to be effective, operators and service companies need to work together to create a comprehensive process to include each phase of drilling: planning, execution, and evaluation. A shock and vibration standard combined with increased client awareness and education have allowed a new level of success to be set at the rig site. Now, shock and vibration issues at the rig can be flagged in real-time and monitored remotely from an operations support center (OSC). This communication structure, coupled with pre-job planning and modeling and the capture of post run lessons learned, can be used to offer solutions when problems arise; thus preventing damage to the BHA, reducing rig non productive time (NPT), and improving the rate of penetration (ROP). Introduction In 1984, a concerted effort was made by service companies to improve the mean time between failures (MTBF) for MWD systems. Besides a tool redesign and improved repair and maintenance initiatives, service companies began using modeling techniques to improve BHA design and reduce downhole shocks and vibrations.1 The first real-time vibrations measurements sub was developed in 19892. Over the next few years, step change improvements in MWD transmission capabilities led to a better understanding of the downhole environment by use of the vibration subs at different intervals in the BHA. The increase in data and accurate modeling allowed for the first integrated shocks and vibration mitigation plans from operators to be developed in 1994.3 This approach showed significant savings by using all of the shock and vibration tools available at the time. The results of this study concluded that service companies would need to take the next step in developing and applying these techniques in the industry. Since 1994, many methods have been published to improve downhole drilling efficiency through the reduction of downhole vibrations. Dynamic modeling programs to identify ideal drilling parameters, advancements in bit design, and improved mud systems have played a key roll in reducing drilling problems in high risk environments. In spite of the vast amount of knowledge surrounding the subject, many operators still view these types of interactions as inevitable, attempting mitigation on a well-by-well basis as the problems occur. While there are no definitive, industry-wide statistics on the percentage of NPT associated with S&V, previous studies have shown that as much 75% of lost time drilling incidents lasting more than 6 hours were associated with drilling mechanics.4 Vibration-induced failures—washouts, twist-offs, downhole tool failures and uneven or excessive wear on tubulars—are severe and costly, amounting to millions of dollars in losses for the industry annually. Sustained high levels of vibration increase the rate of drill string and top-drive fatigue. S&V can also have a significant impact on drilling performance, affecting distance drilled, ROP, and downtime for repairs and maintenance. High levels of torsional vibration and stick/slip reduce the efficiency of rotary steerable systems, making it harder to achieve the desired directional response. Well bore integrity can also be affected. Lateral vibrations are a direct indication that the BHA collars are crashing into the wellbore, and even less dramatic vibrations can damage unstable formations.

Abstract Saudi Aramco attempted to drill horizontal deep gas Carbonate carbonate wells without utilizing the Geo-steering technique in Hawiyah / Uthmaniyah (HWYH/UTMN) field. In both 8–3/8" and 5–7/8" horizontal sections, muchlong time was spentlost due to low ROP, sidetracks due to drilling in an unwanted pay zone / and a stuck BHA, drilling with TCI or and vertical application PDC bits (originally designed for vertical application). A nNew approach was required to deal with this problem. The reservoir engineers and drilling engineers, together with service companies, approached these wells with a different dimension. analyzed eEach problem was analyzed in detail and solvedfound the solution, utilizing LWD/Geo-steering technique., An improvement in casing design led to reduced MW across the pay zone,. A Ggeo-mechanical study was conducted and implemented its recommendation of drilling in the direction of maximum horizontal stress., This approach utilized utilizedadvanced technology PDC bits designed for horizontal drilling., This approach reducinged drilling costs for over drilling five laterals; compared to the previous five laterals in this carbonate reservoir by over US$ 7.28 million (costs do not include the of additional bits and pipe conveyed logging in these wells in the lateral section of five wells drilled without the use of geosteering technique is not considered for simplicity). Utilizing the Geo-steering Technique in these the carbonate reservoir increased the length of pay from 6,360 ft to 15,400 ft, an increase of 142% over a five-well average. It reduced the number of days required to drill five laterals from 364 days to 129 days, a reduction of 65%. Total lateral footage drilled for these five laterals reduced from 24,251 ft to 19,898 ft, a reduction of 18%. The average ROP improved over five wells from 6.11 ft/hr to 12.67 ft/hr. The average footage drilled per day increased from 66 ft/day to 154 ft/day and average number of bits used per well reduced from 13.4 bits to 3.6 bits per well. No sidetrack was required. One of the recent wells was drilled in record time for a HWYH/UTMN Hawiyah / Uthmaniyah horizontal well and was also the longest single-lateral horizontal well in the field. One of the 8–3/8" PDC bits achieved record performance by drilling 4,475 ft in 261.5 hrs with an average ROP of 17.11 ft/hr, representing one of the longest intervals drilled by any 8–3/8" PDC bit in Khuff-C carbonate reservoir. Introduction Saudi Arabia is best known as the world's largest oil producer averaging 8.1 million barrels per day and for having the world's largest oil reserves (259.4 billion barrels as of 2003 year end). The Kingdom also holds the world's fourth largest natural gas reserves of 234.5 trillion standard cubic feet and produces 6.9 billion standard cubic feet per day of non- associated gas1. Saudi Aramco began a major non-associated gas expansion program in the 1990's. This program added 55 trillion standard cubic feet of non-associated gas reserves. Most of the produced gas is in the form of sales gas (a mixture of methane and ethane) and is sold to domestic customers as fuel and petrochemical feedstock. To meet the forecasted domestic gas demand of 12 billion standard cubic feet per day (bscfd) by 2025, Saudi Aramco is accelerating its deep gas well development and exploration drilling campaign in the Khuff and Pre-Khuff formations.Saudi Aramco currently operates 46 drilling rigs for both onshore and offshore operations, out of which 13 are deep onshore drilling rigs for Khuff and Pre-Khuff gas well development and exploration wells. Four more deep drilling rigs are being added in 2005 for drilling gas wells. Moreover, Saudi Aramco has signed four extensive gas exploration and development agreements in the Rub' al-Khali basin with Sinopec, Lukoil, and two consortiums i.e:. Shell & Total, and ENI & Repsol YPF. Economic importance of Khuff reservoirs The Khuff reservoirs are responsible for approximately 75% of Saudi Aramco's current 6.9 bscfd of non-associated gas production. Practically all of the gas produced in Khuff comes from Khuff-A, Khuff-B and Khuff-C reservoirs with Khuff-C being the most prolific.