The terms auto, natural, and in-situ gas lift all refer to artificial lift systems that use gas from a gas-bearing formation to gas lift a well. The gas lift gas is produced downhole and bled into the production tubing via an auto gas lift valve designed for gas operations.The value of auto gas lift is probably easier to demonstrate than for other types of intelligent well because it provides a direct replacement for conventional gas lift equipment, compressors, and pipelines, and the ancillary equipment they require.An estimated 60 auto gas lift systems have been installed at the time of writing of this paper, most of them in the Scandinavian sector of the North Sea. Several papers have discussed this technology, but so far none has presented a rigorous analysis or solution of the wells' production from a gas lift perspective.This paper presents the basic theory behind auto gas lift and how to apply it. The components of the theory are well known and commonly used in nodal analysis and conventional gas lift design. Properly combining these components enables an auto gas lifted well's performance to be calculated and downhole equipment to be correctly sized and located.

Horizontal wells increase the reservoir-wellbore contact area, allowing the wells to produce at higher flow rates with smaller drawdowns which is especially important in oil reservoirs with a large gas cap or aquifer. Long wellbore lengths can lead to production challenges such as water or gas coning and cusping, an unwanted fluid breakthrough from high-permeability zones, and uneven inflow along the wellbore and nonuniform reservoir sweep. Inflow control devices (ICDs), based on well-established technology, have been used in hundreds of wells worldwide. Different ICD types and design methods are available and can be applied to mitigate some of the production challenges. The ICDs are installed as an integral part of the sand screens in the well completion hardware. They can be passive, where the ICD size and configuration does not change after it is run in the hole, or autonomous, where the ICD adapts to changes in downhole fluid-flow properties. However, the decision regarding the use of ICDs as well as the design criteria and selection has to be made prior to the well completion operation. This paper presents a feasibility study on an ICD application in an offshore Nigeria delta oil field with multiple hydrocarbon-bearing reservoirs. Most of the development wells in the field have horizontal openhole 1,000 to 3,000 ft drain sections completed with standalone screens. Strong aquifer and reservoir heterogeneity create production challenges associated with early water breakthrough and suboptimal reservoir sweep. This paper presents a detailed approach to ICD design, sensitivity analysis, and completion optimization, which is based on the coupling of a 3D reservoir model, segmented wellbore model, and ICD models. The proposed ICD completion design is evaluated and sensitized to subsurface reservoir uncertainties using volumetrics. The final decision process is presented to guide the selection and feasibility of an ICD application for two reservoirs.

In this paper, we evaluate optimization techniques to develop, or support, business cases for Intelligent or Smart Wells. A commercial reservoir simulation platform and two reservoir models based on published work are used. Recommendations are made on which methods are most appropriate for large or small numbers of flow control valves (FCVs), available computing power and other parameters. Optimization techniques are categorized as either Closed Loop or Model Based. Closed Loop or Reactive methods respond to specific, measured properties such as water-cut or gas-oil ratio, by opening or closing downhole flow control valves. Model-Based methods use reservoir models to determine the optimal set of flow control valve positions versus time. They can, therefore, behave in a defensive or proactive manner to delay the production of unwanted fluids, as well as a reactive manner, to choke back sections of the well producing unwanted fluids. In this paper, Closed-Loop and Model-Based methods are compared in terms of computational cost. A simple procedure for defining the constraints used in the optimization process is proposed. The procedure is shown to increase the efficiency of the optimization process significantly.

The Chestnut field is located in Block 22/2a in the central North Sea. The field, with water depths to 120 m, is approximately 180 km east of Aberdeen, Scotland. Chestnut was first commercially produced in September 2008 by Centrica Energy (formerly Venture Petroleum) using two subsea wells (a horizontal oil producer and a water injection well) tied into a floating production, storage, and offloading (FPSO) vessel. Water injection was required almost immediately because the oil was saturated. A second oil producing well was spudded in September 2008, targeting the South Chestnut field. This well, 22/2a-16Y, was tied into the same flowline and riser as the existing oil producer. A venturi-type downhole flowmeter was installed in well 22/2a-16Y to obtain continuous pressure, temperature, and flow rate measurements. The production from the other well could then be calculated by subtracting the venturi flowmeter measurements from the total rate measurements made at the FPSO. Venturi-type downhole flowmeters are, strictly speaking, only applicable in liquid environments because the Bernoulli principle is valid only for single-phase flow and is tenable only in low-slip liquid-liquid flow regimes, such as in the concurrent flow of oil and water at high velocities. Because the Chestnut oil is saturated, it was known that free gas would be seen at the intake of the venturi because the flowing pressure would, by definition, be below the bubblepoint. To address the challenges caused by two-phase flow through the flowmeter, a workflow was developed that would first assess the quantity and affect of the free gas in the venturi device. The workflow was then developed to increase the accuracy of the flowmeter in the two-phase oil-gas flowing conditions. The enhanced flow calculations were then validated by using FPSO test separator data when only the flowmeter-equipped well was producing. The enhanced model improved the accuracy of the liquid-rate predictions across various rates from initial discrepancies of 40% to 190%, to less than 5%, allowing Centrica Energy to achieve its well- and reservoir-monitoring objectives. The use of venturi-type flowmeters has traditionally been limited to applications in which only liquid is flowing through the meter. This present case study shows that customized workflows can improve the accuracy of the venturi flowmeter measurements in multiphase environments, making these downhole flowmeters a cost effective alternative to true multiphase meters for certain applications.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe terms auto, natural or in-situ gas-lift all refer to artificial lift systems that use gas from a gas bearing formation to gaslift a well. The gas-lift gas is produced downhole and bled into the production tubing via an auto gas-lift valve designed for gas operations. The value of auto gas-lift is probably easier to demonstrate than for other types of intelligent well because it provides a direct replacement for conventional gas-lift equipment, compressors, pipelines and the ancillary equipment they require. An estimated 60 auto gas-lift systems have been installed at the time of writing this paper, most of them in the Scandinavian sector of the North Sea. Several papers have discussed this technology but, so far, none have presented a rigorous analysis or solution of the wells' production from a gas-lift perspective. This paper presents the basic theory behind auto gas-lift and how to apply it. The components of the theory are well known and commonly used in Nodal analysis and conventional gaslift design. Properly combining these components allows an auto gas-lifted well's performance to be calculated and downhole equipment to be correctly sized and located.