fax 01-972-952-9435. AbstractMany modern well construction techniques have been developed with an eye toward drilling deeper, longer, and more cost effective Extended Reach Drilling (ERD) wells. One notable technology that has contributed to this effort is solid expandable tubulars. This technology was developed specifically to allow additional casing strings to be run to cover up problem zones and facilitate drilling the well to the ERD target. Solid expanable tubulars also help to reduce the overall resources required to construct the well. Projections show that using them would significantly reduce the size or volume, as well as the cost of the rig, the drill string, the bits, the cement, and, of course, the casing, resulting in lower overall costs. This result has been born out in practice and will culminate in the single-diameter well described elsewhere. 1 The effects on ERD wells will be substantial, but there are important 'side effects' that can have a profound cumulative effect. The torque and drag on an ERD well is usually the limiting factor in the actual reach possible. These limits are mitigated by drilling fluid properties and the use of rotary steerable drilling tools among other technologies. Torque and drag are primarily influenced by geometric conditions like dogleg severity (DLS) and casing open hole size vs. drill string size, surface effects (commonly grouped together and named the friction factor), and drill string dynamic conditions (such as axial and rotary motion that overcomes the friction). The use of solid expandables has two distinct effects that can be favorable for the drilling of ERD wells. An important effect is that more favorable drill string casing geometry is possible and can reduce the tendency for helical buckling or drill string lockup. Another important impact is the ability to use larger drilling tubulars. This paper will examine data supporting the positive effect of solid expandable tubulars on drill string torque and drag. Data modeled for an ERD well shows the theoretical drilling limit improvement from these effects in real example wells. Extended reach drilling limitations have been pushed out significantly in recent times. Advances in mud systems, geomechanics, and the advent of rotary steerable systems have significantly improved the ability to reach further to access hydrocarbons. However, limitations, though receding, still exist. To counter them, new approaches are being developed that attack in various ways the traditional boundaries of extended reach drilling applications.

In the past, junction construction technology has driven the design of multilateral wells. This practice has led to technical successes that may or may not have met all of the operator's desired well objectives. These projects have often been regarded as less than successful from an economic point of view. This regard is partly due to the way that junction construction has been viewed. Junctions are presently classified by looking at the technical differences in how they are constructed, such as TAML levels (Technology Advancement - Multi Laterals)1. Although this method is suitable for looking at junction construction complexity, it does not address directly what the junction does in service. Another approach would be to drive the design using information about reservoir/production requirements. Looking at functional groups of junction features will allow the drilling or completions engineer to make sense of the myriad of available junction systems. This technique can help optimize the multilateral junction type selection for a given project. The process of planning multilateral projects from conception through well design will be discussed with a focus on using a functional classification map to clarify the junction requirements. The Functional Classification Method will assist engineers in comparing equipment options. This comparison is accomplished by, first, defining the reservoir and economic drivers, and, then, by selecting the appropriate junction attributes. Furthermore, the method will provide a process for assembling the data required to prepare the final well design and to prepare precise tender documents. To illustrate this method, recent examples from the Middle East will be presented. Introduction Historically, drilling engineers have struggled to design a well that would accommodate a given multi-lateral completion while meeting all of the reservoir depletion requirements. As a result, there have been a number of failures when attempting to install these systems. Looking at multi-lateral technology and its real function in the oil industry, it becomes apparent that it is not a drilling tool at all. Instead, it is a reservoir depletion tool. Shifting the ownership of this technology provides an opportunity to see the planning process in a new light. The concept of multi-lateral drilling is essentially one of reservoir depletion economics. It is one answer to the question of how to get the most production for the lowest cost. By starting the planning effort in the reservoir camp, the equipment selection process is enhanced. Only after the reservoir mechanics are considered and the depletion requirements defined, can an unbiased judgment be made regarding equipment selection. To aid in this selection, an optimized multilateral planning process was developed. The process map will guide the engineer to a number of junction attributes that can then be used to select and compare various vendor systems. In the event that no systems perfectly match the required attributes, the information can be used as the basis for a compromise. If no compromise is sufficient, this process will provide the basis for tendering a request to design/build the required system2. All desired outcomes from a drilled well fit in one of two categories: to obtain information or to promote hydrocarbon retrieval. No matter what the multilateral well design, or which equipment is used in the well, multilateral technology's only purpose is to do these things more effectively or more economically. The challenge is to provide only the functionality that is essential to meeting the minimum well requirements. Then functionality that is desired but not necessary can be evaluated on a cost-benefit basis prior to acceptance to the well plan.

In the past, solid expandable casing technology has often been successfully used as a contingency measure to minimize the loss of hole size while dealing with drilling problems. Other applications, such as overall reduction of casing string sizes and numbers, sidetrack applications, and production conformance applications have been slower to attract interest, even though they are all technically viable and economic. This paper will investigate the process for successfully integrating solid expandable tubulars into all aspects of the well construction program. Preparing the hole section for the installation of the solid expandables will be discussed. Drilling, completion, and production operations through expanded tubulars will also be reviewed. The process of planning solid expandable projects from conception through well design will be investigated, focusing specifically on the ancillary technologies in the drilling, completion, and production phases. When all aspects of the well construction are optimized, the greatest economic value of solid expandables is achieved at the minimum operational risk. Optimizing the Casing Design There are several avenues to consider when optimizing well design with expandable casing. Opportunities exist to save resources merely by reducing the casing size itself. In addition, optimization changes are available by drilling in the most favorable size ranges: not too small, and not too large. Reductions in size of the hole drilled generally result in savings. Reduced deliverability and flexibility in the smaller wellbore is balanced by savings in top side costs, such as location or platform costs, tubular costs, and mud products costs. Current costs from operators in the Middle East indicate that these savings are on the order of 20 to 40% when one full casing size is eliminated. As technology improves, it increases the the length of producible sections and enables the operator to place wells in the optimum spot in a pay zone. As a result, operators are increasingly reluctant to compromise deliverability with a small final hole diameter. In addition to the deliverability issue, a conventionally-drilled slimhole design lacks some flexibility to manage with unexpected well problems. If a serious lost circulation zone or an overpressured zone is encountered, there may not be enough diameter remaining in the existing hole to drill the well to total depth. There may also not be enough room left to deal with corrosion or cement isolation problems. In general, there are specific hole sizes that are more cost effective to drill than other hole sizes. For example, it is generally accepted that hole sizes below 7–7/8 in. are generally more difficult to drill than larger sizes. Smaller bits and other bottomhole assembly (BHA) parts can be less durable due to their smaller mass. The assemblies are also quite flexible, which can lead to drag and buckling problems. The lack of space available to design engineers can mean that stress concentrations may not be easily removed from parts and that re-enforcing may not be simple. In items that have moving parts, like roller cone bits, roller reamers, and other downhole tools, there is difficulty scaling down parts due to size, strength, and heat dissipation issues. Scaling down can lead to problems dissipating heat that, in turn, reduces the bearing and cutting structure life. Similarly, hole sizes above 12 inches tend to be challenging to drill because scaling up all the components of the drilling BHA is difficult and expensive. Typically only the bit and a few collars and stabilizers will be near the hole size. Every other part of the drillstring will be undersized. Undersizing leads to pump and hydraulics problems such as annular velocity needed for hole cleaning, cuttings loading, and equivalent circulating density. There is also the sheer size of the hole to consider. Larger holes require more drilling mud, a bigger volumetric flow rate, larger pumps, more solids control equipment, more waste disposal, and more expensive BHA parts. Lastly, and probably most important, the larger hole sizes require more rock to be crushed and removed, more steel for casing, and more cement for zonal isolation.

fax 01-972-952-9435. ProposalWhen most operators think of solid expandable casing, they primarily focus on their application as it relates to solving hole problems while minimizing any loss of hole size incurred by running a casing string. A new application for solid expandable casing quickly growing in popularity uses the tubulars to sidetrack through a milled window. Solid expandable casing can minimize, if not eliminate, many of the obstacles associated with sidetracking.The historic drawback of losing hole size through the window exit can be largely eliminated by using solid expandable casing. These tubulars enable the hole section to be drilled beyond the expandable casing with larger drill pipe and bottomhole assemblies (BHAs), including measure-whiledrilling (MWD) and logging-while-drilling (LWD) tools, which may have been impossible with a conventional sidetrack. Larger production tubulars and related completion equipment add to the value generated by using the solid expandable casing. This technique can also be instrumental in initiating slot recoveries that might not otherwise be economically viable.As with other applications of solid expandable casing, a successful installation requires proper pre-job planning. This paper reviews issues critical for success and also looks at specific examples of installations performed to date. Other technologies associated with expanding the solid casing will also be discussed in the context of wells already completed or in the planning stages. The economic benefits of this technique will also be explored.

The benefits of drilling multilateral wells in slot limited applicationssuch as offshore platforms are well known. Using multilateral technology in aproject can minimize facility costs, reduce drilling costs, maximize reservoirexposure and reach secondary targets. When a project is in the planning stage, there is often resistance to multilateral concepts due to a perception ofincreased operational risks and doubts that the economic benefits will be fullyrealized. The key to broadening the implementation of this technology ismatching actual opportunities with robust, reliable multilateral systems. In a project in the Arabian Gulf, an operator implemented the use ofTechnical Committee for the Advancement of Multi Laterals (TAML) level 5pressure isolated junction systems with through tubing access to develop asingle reservoir in a slot limited application. Both pre-milled and retrievableoriented milled window technology were used as a platform for the completedjunction. This illuminates how this technology is used in new or existingwells. A study of how the unique operational issues were solved illuminates thesuccess of the application of this technology to this project. It will alsoprovide an insight into best practices to aid in the planning and execution ofother complex well types. Operational and economic results, as compared tosingle lateral wells on the same platform, provide insight into many advantagesrealized in this program. Introduction The prevailing reservoir management philosophy in Saudi Arabia is tomaximize reservoir exposure in each well. This is projected to increase theproductivity of each well or drilling slot. This will also reduce well problemsthat are exacerbated by high draw down such as coning or cresting, solidsproduction, or wellbore stability. Multilateral technology can assist in theapplication of this philosophy in several ways such as: Adding more footagethrough the addition of laterals, increasing the drainage area by covering moreareal extent with laterals, and making the drilled footage more productive byadding flow control and remedial capabilities to the well. In a field development the Arabian gulf, the primary zone of development atthis time is a sandstone, though several other zones are indicated in thearea. Ongoing reservoir management considerations suggested that multilateralwells would accelerate production from the eastern flank of the field. The project team was challenged with maximizing reservoir drainage from theplatform. To achieve this plan, medium reach horizontal wells along withmultilateral legs were evaluated in the reservoir model. Although all of thewells on the platform were indicated as potential for applying multilateraltechnology, only the last two were planned due to expected delivery time forthe equipment. A sub-team from the Marjan project team was formed with thefollowing objectives:Technically evaluate the drilling and completion equipment on the market forre-accessible drilling junctions.Determine the available completion alternatives.Evaluate full cycle operations and costs (drilling, completion, workover andproduction) to evaluate the long term operating/workover cost of the well.Evaluate the applicability of this technology to other areas within SaudiArabia.