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.

A method is described for combining multiple wellbore surveys to obtain a single composite, more accurate, well position. Established methods for defining the wellbore position, and its associated uncertainty, rely upon accepting the position obtained from the most accurate survey instrument used in each section of the wellbore. This position is then assigned an uncertainty based on the information from this single survey instrument run. Today, when a modern wellbore is constructed, each section may be surveyed for position many times using one or more magnetic, gyroscopic or inertial survey instruments. By statistically combining the wellbore positions obtained from all of the survey instruments run in a given section of the wellbore a new position, designated the ‘Most Accurate Position’ (MAP), is calculated. The main advantage of the MAP is that its uncertainty is smaller than the uncertainty of any of the constituent surveys. The major benefits of this technique will be to facilitate the drilling of smaller targets at greater distances, allow the drilling of new wellbores in closer proximity to existing wellbores while maintaining accepted safety clearance rules, and improved reservoir delineation. Describing Well Position The wellbore trajectory is defined as a series of surveyed points in three-dimensional space typically described in a North, East and Down reference system. These points are joined together to form a continuous trajectory using a geometrical calculation method1. Most magnetic or gyroscopic survey instruments in use today provide a survey point that is referenced to measured [or along hole] depth that is obtained from the driller's pipe tally, or from a wireline spooling measurement. The survey instrument provides inclination (hole angle) and azimuth (direction) measurements. When these parameters are used to calculate trajectory with an assigned survey depth, the horizontal displacement [or North and East coordinates] from the origin, and the vertical depth [or Down coordinate] from the elevation reference can be derived. Alternatively, some inertial survey instruments measure displacement in three-dimensional space from a known initialization point, and from which all of the above parameters [including depth] can be obtained to achieve the same purpose. Wellbore Position Uncertainty Wellbore survey requirements are typically driven by the need to guide the well to a geological target, to avoid other wells, to ensure that property boundaries are respected, and to record the position of the wellbore for future reference. In order to visualize and quantify our ability to hit a target or avoid colliding with another well, position uncertainty is assigned to wellbore trajectories. This position uncertainty represents our modeled knowledge of the collective errors arising from both the intrinsic performance limitations of the survey sensors and those induced by the operating environment2. This uncertainty is defined as a statistical confidence region with an associated confidence level. In three dimensions the confidence region is most often depicted as an ellipsoid3 because ellipsoids are the constant value contours of the three-dimensional Guassian probability density function. Such a confidence region is commonly referred to as an ‘Ellipsoid of Uncertainty’ (EOU). The EOU is used in target analysis, for example, by reducing the size of the geological target by the size of the EOU to define a drilling target. In this fashion, the geological target will be achieved if the wellbore penetrates the drilling target. Likewise EOUs are used to assess collision risk by considering the proximity of the EOUs from adjacent wells.

Complex drilling programs in crowded downhole environments are increasingly common today, placing a premium on effective techniques for avoiding wellbore collisions. The costs of such incidents, both in financial and safety terms, can be extremely high. The authors have developed a comprehensive and effective approach to wellbore collision avoidance, as confirmed by a number of consistently successful projects. Based on their experiences in the field, the authors believe the time has come to establish an industry-wide standard for evaluating, minimizing and mitigating well collision hazards. This paper will outline their approach and provide case studies illustrating the high cost of such collisions and the value of an effective process for identifying-and eliminating or reducing-their likelihood. The approach described is flexible enough to accommodate the different challenges each unique field presents, and has proven equally effective in projects ranging from simple vertical wells to crowded land pads, offshore platforms, deepwater/subsea and fishbone multilateral designs. Well position uncertainties are determined by using survey error models from the Industry Steering Committee on Wellbore Survey Accuracy. Drilling program recommendations are based on the status and conditions of adjacent wells and the nature and magnitude of potential risks associated with a collision. Developing a standard based on this approach will equip the industry to achieve increasingly complex and ambitious goals without compromising safety or incurring unacceptable losses or risks by ensuring the targeting of the correct limited resources and expertise where they are most needed.

A man-made island and buried subsea pipeline are needed for an oil production project within the Foggy Island Bay area of the Alaskan Beaufort Sea. In order to characterize the geologic and permafrost conditions in the area, field data have been collected over several winter field seasons. Multiple subsea buried pipeline alignment options and several potential island sites have been studied. Over the years, the arctic exploration teams have completed 600 boreholes, 75 piezocone penetration test (CPT) soundings, subsea temperature measurements, and performed comprehensive laboratory programs on frozen and unfrozen sediments. The shallow subsurface geologic conditions within Foggy Island Bay range from loose silty sand and soft to firm fine-grained marine Holocene deposits to stiff Pleistocene silty clay deposits. Shallow permafrost is present in Foggy Island Bay, primarily near the Boulder Patch and within the shoreline transition zone. The results of the near surface geotechnical conditions are discussed and presented with respect to subsea pipeline constructability and design parameters. Trench constructability and wall stability is discussed, as well as the frozen and unfrozen backfill properties important to resist upheaval buckling when the pipeline goes into production and begins to thaw the frozen backfill. This geotechnical summary serves as a resource for enhanced understanding of soil, permafrost, and sea-ice properties in the Alaskan Beaufort Sea.

Current trends in drilling require a proven and comprehensive approach to assessing and managing the risks of wellbore collisions. This paper outlines the scope and nature of the challenges in collision risk management, and provides an overview of a systematic, field-tested approach to identifying, evaluating, eliminating and/or mitigating those risks. Key aspects of the process are explained in detail and a recent field application on a large platform offshore Indonesia is discussed to illustrate the key values of the risk management process. These include maximizing resource recovery by permitting the safe, precise placement of wellbores, and minimizing the financial and human cost of losses from incidents avoided or mitigated.