fax 01-972-952-9435. AbstractHorizontal wells have dominated the conventional wells due to their increased production rates, improved recovery efficiency, increased reservoir drainage area, and delayed gas and water coning. However, non-uniform flow profiles can result in premature water / gas production, loss of production and reserves, and decrease in profitability, which will shorten the life, and defeat the purpose of a horizontal well. This paper will describe a new production technology system that will optimize production, delay water / gas coning, eliminate / minimize annular flow, and ensure uniform inflow along the lateral at the cost of a minute pressure drop in long, high-rate horizontal wells. Case history will be presented from Saudi Aramco, where this production technology, combined with sand control technology, has resulted in significant saving for the operator, and improved production in horizontal offshore oil wells.

This paper describes case histories of a successful drilling and completion experience of two tri-lateral Maximum Reservoir Contact (MRC) wells that were recently completed in Haradh field, Saudi Arabia. Equipping these two wells with down-hole monitoring and lateral flow-control, combined with the introduction of new completion practices, provided effective reservoir management solutions. A number of different MRC well designs were drilled and completed in different fields in Saudi Arabia, however, the subject two MRC wells were the first to provide minimum inter-lateral separation distance of three hundred meters. Moreover, these two MRC wells were the first to be completed with seven inch tubing string and tree, and equipped with per-lateral flow control option to selectively shut-in any water baring lateral in order to extend the life of such wells. The objective behind the introduction of this new class of well design, the so called (MRC), which is generally defined as well with reservoir contact of five km and beyond, was to improve individual well productivity and hence reduce the unit development cost and to better develop hydrocarbon assets1. Various reservoir and drilling challenges were encountered during the planning and execution phases of this project. Meeting the required minimum inter-lateral separation distance, expected production rate, and providing selective flow-control form each lateral were the main drivers for the current well design. Other challenges such as loss circulation, torque and drag limitations, well control, and formation damage were encountered while executing the project and were overcome successfully using different creative techniques that are also discussed in depth in this paper. Introduction The Haradh area of Ghawar field, discovered in 1949, in the southern most portion of the Ghawar field, is approximately 11 miles (18 Kilometers) wide and 47 miles (76 kilometers) long. Regular oil production began when GOSP-1 come on-stream in 1964. The Arab-D reservoir produces Arabian Light crude. Haradh, part of the greater Ghawar field, is divided into three increments (Figure 1). Increment-1 was put on production in 1996, Increment-2 was being developed at the time this paper was written and is the subject of discussion in this paper, and Increment-3 is yet to be developed.

The oil and gas industry has continually made an effort to stay abreast of oilfield needs so that operators could meet the challenges of deeper reserves as well as access the oil and gas reserves that were previously considered as technically and/or economically prohibitive. To meet the challenges, the engineering companies have continued to develop state-of-the-art equipment and advanced software. Today’s well designs are inherently more complex, since the current targets are deeper, requiring extended-reach configurations, or are in locations that present greater difficulties in developing appropriate well designs. Success, therefore, is even more dependent upon careful up-front planning so that the proper technologies will be employed to ensure that the sought-after goals are attained. Extended-reach wells carry significant risks where cost of failure regarding the deployment of the liner and liner hanger system could consume the whole well. One of the major risks with deploying a long liner is the risk of pre-setting the liner hanger and/or the liner hanger packer. This paper will focus on an expandable liner hanger (ELH) system recently introduced to the industry that can mitigate these risks. The ELH design and unique setting procedure will be the focus of this paper. When the liner is deployed using the detailed analysis generated during the planning stages, the risks mentioned above can be significantly reduced, and greater assurance that the liner can be run to depth can be provided. Other risks in the extended-reach sections of these wells concern problems relating to friction (drag) during the deployment of the liner hanger. This phenomenon can be addressed with a new ‘torque and drag’ software program that can be used to optimize the solution. This software produces a detailed analytical output that will provide a model with guidelines to aid in deployment of the liner into the wellbore. The analysis also will help determine whether centralizers should be used (and if so, specific spacing), whether fluids that will reduce the friction coefficients should be considered, and will also examine whether there is the possibility or a need of floating the liner assembly to depth. To summarize, the ultimate goal of the well designer is to use the available software to assess the wellbore, and then, to build an optimized plan of the liner assembly and how it should be deployed so that the liner, expandable liner hanger and drill pipe can reach depth with minimal risks. Using this approach can help eliminate non-productive time and relieve the potentials for high-cost impact. The case history used here will illustrate how the proper planning in this well and use of the ELH system selected was capable of addressing the challenges of successful deployment of an expandable liner hanger system in an extended-reach well for Saudi Aramco. These wells typically have measured depths (MD) of 19,000 to 31,000+ feet and true vertical depths (TVD) between 7,000 and 9,000 feet. The liner lengths range from 5,000 to 10,000 feet in length.

Over the course of time, the oil and gas industry has increased its usage of state-of-the-art equipment and advanced software to access oil and gas reserves that were previously considered as technically and/or economically prohibitive. Today's well designs are inherently more complex since the current targets are deeper, require extended reach configurations or are in locations that present greater difficulties in developing appropriate well designs. Success, therefore, depends upon careful up-front planning to ensure that the goals sought are attained. The planning requires detailed calculations at each step of the well development ? from the geological survey to drilling to completing the well. The advanced modeling software available in the market today has made the required analysis possible. Extended-reach wells carry significant risks where cost of failure regarding the deployment of the liner and liner hanger system could consume the whole well. One of the major risks with deploying such a long liner is the risk of pre-setting the liner hanger and/or the liner hanger packer. An expandable liner hanger (ELH) system, recently introduced to the industry, inherently eliminates this risk with its design and setting procedure and is the focus of this paper. When the liner is deployed using the detailed analysis generated during the planning stages, the risks mentioned above can be significantly reduced and greater assurance that the liner can be run to depth can be provided. The extended-reach section of these wells creates additional problems relating to friction during the deployment of the liner hanger. This phenomenon can be addressed with 'torque and drag' software as well as 'surge and swab' software to optimize the solution with a detailed analytical output that will determine the best method to use to deploy the liner into the hole. The analysis will help determine whether centralizers should be used (and if so, specific spacing), whether fluids that will reduce the friction coefficients should be considered, and will also examine whether there is the possibility of floating the liner hanger to depth. To summarize, the ultimate goal of the well designer is to apply the available software to develop and optimize a plan to reduce friction during deployment of an expandable liner hanger to depth while reducing cost impact and eliminating nonproductive time. The case history in this well will verify how the proper planning and use of the ELH system selected was capable of addressing the challenges of successfully deploying the ELH system in an extended-reach well for Saudi Aramco. These wells have a measured depth (MD) of 19,000 to 31,000+ feet and true vertical depths (TVD) between 7,000 and 9,000 feet. The liner lengths ranged from 5,000 to 10,000 feet in length.