Today's increasingly complex and crowded drilling environments have placed a greater emphasis on wellbore collision avoidance. The safety and financial implications of shutting in production on platforms or repairing damaged wells have established a need for the industry to evaluate the potential for collision with a producing well. This paper will describe an effective approach to evaluating, minimizing and mitigating these hazards, and will include a number of case studies illustrating the successful application of this approach in the field. This paper, the latest in a progressive series will detail the importance of gathering appropriate data—such as completion type, offset surveys, well pressures, casing depths, reservoir fluids and mud densities—and analyzing this data to accurately assess potential collision risks. Each well and field poses different challenges; not all data is available and wells can vary from simple vertical land wells to crowded offshore and fishbone designs. The well position uncertainties are determined by using survey error models from the Industry Steering Committee on Wellbore Survey Accuracy. This method was chosen because it is an industry-recognized standard of defining the magnitude of survey uncertainty. Recommendations for minimizing risk are based on the status and conditions of the adjacent wells and the nature and severity of the risks associated with a collision. These recommendations are formulated to minimize the risk while ensuring that production is disturbed as little as possible. Introduction With the worldwide growth in drilling activity, operators are encountering increasingly complex and crowded drilling environments, especially in previously developed fields where existing well density is high and legacy positional data often unreliable. The safety, environmental and financial consequences of a wellbore collision can range from minor to catastrophic, and the cost of shutting in nearby producing wells during drilling or repairs can be prohibitive, causing producers to bypass otherwise viable opportunities. As part of an international drilling and services provider (the Company), the authors have worked in close collaboration with client organizations to understand and meet these challenges. Because no industry-wide anti-collision (AC) standard exists, the Company has established its own standard and a comprehensive anti-collision AC process for meeting it. To comply with the AC standard when any new well is drilled, the drilling engineers must analyze each of the offset wells within a certain radius of the proposed subject well. This can be a relatively quick and simple process in a new field where only a few wells are involved. In such situations, the AC process might take no more than a few hours and be solved at the location level. But in highly developed brownfield locations, the AC process becomes much more complex, requiring the analysis of hundreds of adjacent wells before finalizing a new trajectory. This paper will illustrate the design and application of the Company's AC process, including a number of success stories from real-world drilling assignments. Lessons learned from these experiences feed back into the development process to achieve a continuous improvement in its effectiveness and breadth of application. The Challenge of Avoiding Well Collisions A number of recent trends contribute to an ever-increasing complexity in the AC process. In land drilling activities, new production in older, established fields can pose an increased hazard of collisions with existing wells. In some parts of the United States, for example, rules concerning well density have been relaxed to facilitate more domestic production. From a former spacing limit of one well per 25 acres, new regulations have reduced that to a 20-acre limit and then a 10-acre limit, with proposals for a 5-acre limit in the future. The same trend worldwide has opened opportunities for producers to return to established fields with an infill drilling campaign, placing new wells between and in relatively close proximity to existing wells, which are often still producing.

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.

Materials in drilling muds are known to sometimes distort the geomagnetic field at the location of the Measurement While Drilling (MWD) tool magnetometers that are used to measure the azimuth of well path. This distortion or shielding effect can contribute to substantial errors in determination of azimuth while drilling deviated wells and with significant well displacements, these errors may result in missing the target of a long deviated section in the range of 1–200m; and thus impact on the overall productivity expectation of the well. The article describes significant shielding effects observed while drilling long wells. The criteria for acceptance of the surveys were not met and resultantly, an alternative survey source had to be obtained with resulted in increased cost and time to the client. A number of measures were implemented to eliminate this shielding effect. The effects of drilling fluid contamination by magnetic materials are calculated, and a method to evaluate the magnetic properties of the drilling fluid is proposed. The effect of taking measurements with the pumps on versus off is quantified.

SPE 126480 Results and Lessons Learned from a 3-Year Intensive Coral Communities Monitoring During the Construction of a LNG Plant in Yemen.

The current focus of many US land drilling programs is on major unconventional gas shale plays. In this paper, the authors will discuss the challenges posed by and effective solutions developed for wells drilled in one of these plays: the Marcellus Shale. In response to the economic, real-estate, water disposal, and regulatory challenges the Marcellus Shale presents, multiwell pads have become a common approach. Historically, the Marcellus and Appalachian Basin has been developed using inexpensive, vertical wells drilled using the latest technologies and techniques. While some of these options are still viable, changing conditions make proper surveying and anticollision monitoring imperative. The pad design, surveying, preplanning, and execution of successful multiwell pad drilling require extensive collaboration between service providers and operators, a process that will be addressed in this paper.