1 Intelligent Well Technology: Status and Opportunities for Developing Marginal Reserves SPE

SPE XXXXX

Intelligent Well Completion: Status and Opportunities for

Developing Marginal Reserves

Michael Konopczynski, SPE; Arashi Ajayi, SPE; and Leigh-Ann Russell, SPE, WellDynamics International Limited

1 Intelligent Well Technology: Status and Opportunities for Developing Marginal Reserves SPE

Copyright 2008, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 32nd Annual SPE International Technical Conference and Exhibition in Abuja, Nigeria, August 4-6, 2008.

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgement of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract

Marginal reserves are hydrocarbon accumulations too small or too difficult to recover to be developed economically by themselves under prevailing fiscal terms. Stacked reservoirs containing marginal reserves are often passed over in favour of more prolific zones containing economic volumes. The opportunity to develop the marginal reserves in conjunction with other marginal reserves, or with larger reserves by commingling (and by doing so make them economic) is sometimes overlooked by operators due to government regulations prohibiting commingling.

This paper explores the concept of developing marginal and by-passed reserves by commingling using intelligent well technology. It reviews the current status of intelligent well technology and government regulations on commingling in a number of regions. The potential for exploiting marginal reserves in the North Sea, Nigeria and the Gulf of Mexico is considered.

Introduction

A great many of the hydrocarbon accumulations in the world, by themselves, are not economic to develop or produce. In many of the more prolific hydrocarbon basins, multiple reservoirs are encountered stacked one above the other. Conventional government regulations and good petroleum practice prescribe that the production of conventional oil or gas from distinct reservoirs or pools must remain segregated in the wellbore. As the Alberta Energy and Utilities Board explains,

“The purpose of maintaining segregation of oil and/or gas in the wellbore is

  • to avoid the potential for wellbore and/or reservoir conditions that may adversely affect recovery from pools (for example, in some cases the cross flow of reservoir fluids between pools under a commingled-completion operation may jeopardize recovery from other pools involved), and
  • to maintain the ability to gather data on an individual-pool basis for resource evaluation and reservoir management.”1

The traditional methods of exploiting multiple reservoirs from one wellbore are to either develop the reserves sequentially from bottom up, or to use multi-string completions to maintain segregation. The drawbacks of the first method are that it can take a great deal of time to exploit all the reservoirs, and it often precludes the invocation of tertiary recovery methods that have the potential to improve the fraction of hydrocarbons that can be recovered. The drawback of the second method is that productivity from the individual zones and from the well in total can be restricted because the size of the tubing is limited by the geometry constraints of the casing. Casing size can be increased to accommodate the larger tubing required for optimum production, but this is a costly option.

As a consequence, in many of the basins around the world, smaller hydrocarbon accumulations penetrated by a wellbore are passed over in favour of the larger and more prolific pools. Groups of small, uneconomic hydrocarbon pools remain undeveloped, when developed together they may become economic. An operating company may have knowledge, from exploration and development wells, of “marginal” accumulations separate or in addition to a primary economic reservoir. Yet in the current and foreseeable business climate, these reserves have little chance of ever being developed.

This situation is true for many regions around the world, including the Gulf of Mexico, the North Sea, West Africa, the Middle East and the Asia Pacific region.

Commingling

The simultaneous production of hydrocarbon from multiple reservoirs or pools through a single production conduit is called commingling.

There are multiple economic benefits of commingling reserves that can provide very large increases in incremental project NPV for all types of oil and gas field developments. The benefits of commingling production from separate reservoirs are:

  • ability to produce hydrocarbon from multiple reservoirs which may not be economic to produce on their own
  • fewer wells, less infrastructure - lower capital expense
  • lower operating expenses
  • less environmental impact, fewer locations
  • a sustained production plateau

The CAPEX benefits of commingling flow from multiple reservoirs, is immediately obvious in high cost, high productivity deepwater field development applications. However, regulations and practices counter to commingling have been identified as a blocker to the economic development of low deliverability reservoirs2.

The practical issues associated with commingling can be classified by the following categories:

  • Allocation of production to different reservoirs
  • Reservoir Management
  • Prevention of cross flow between reservoirs
  • Compatibility of reservoir fluids
  • Ability to exclude production of unwanted effluent (water, gas)
  • Well integrity and flow assurance

Commingling Around the World -Regulatory Issues

The regulations for the commingling of down-hole production are typically set by government agencies responsible for oil and gas developments.

A review of the published regulations regarding commingling for a number of these agencies in mature hydrocarbon producing areas was reviewed for the purpose of this paper. The U.S. Department of the Interior Minerals Management Service (MMS)3, the Railroad Commission of Texas (TRC)4, the Alberta Energy and Utilities Board (AEUB)5, the Manitoba Industry Trade and Mines (MITM)6, and the United Kingdom Department of Trade and Industry (DTI) are agencies that address commingling in their regulations.

The main reasons that the regulatory bodies control the application of down-hole commingling are as follows:

  • Potential for sub optimal recovery (conservation)
  • Inability to provide accurate flow estimation and allocation for each zone (administration)
  • Concerns about fluid compatibility
  • Minimisation of interventions
  • Concerns about lack of control (cross flow between reservoirs)

There are very few areas of the world that permit commingled flow from different reservoir intervals without approved means of control, testing of segregation, and flow estimation and allocation (FE&A) for each interval. A down-hole commingling permit, obtained from the regulatory body is required in most cases. From a regulatory point of view, commingling may be justified and approved as an exception in the following circumstances:

  • low deliverability of one or more pools due to reservoir characteristics or depletion of the pool by production (economic hardship),
  • small reservoirs that would deplete rapidly under production,
  • operational issues that can be handled more effectively with commingled production, such as liquid loading in the wellbore, hydrate formation, or physical limitations in the wellbore (e.g., a casing diameter that is too small to contain two production strings),
  • induced communication behind the casing through a poor cement bond or fracture stimulation, and
  • where it has been demonstrated that the commingling will not affect ultimate recovery of oil or gas from the field.1

Canada’s Manitoba Industry Trade and Mines Drilling and Production Regulations are a good example of the documentation required in an application for an exception to the rule permitting commingled production.6 The MITM request the following information during the application process:

i.)maps showing the interpreted structure, effective reservoir thickness, areal extent and fluid interfaces of the pools; and

ii.)a discussion of:

a)the ultimate reserves associated with each pool recoverable through the well;

b)the proposed method of allocating production or injection to each pool, including testing frequency;

c)reasons justifying the proposed commingling, including specific economic data; and

d)the impact of commingling production or injection on ultimate recovery from each pool and on the correlative rights of owners; and

e)any other information the director may require.

Commingling Legislation

In the United Kingdom, the Department of Trade and Industry (DTI) sponsored PILOT Undeveloped Discoveries Workgroup estimated that 15% of discovered, uneconomic oil reserves in the UK Sector of the North Sea could be made economic by commingling7,8. Similar gains in proven reserves through commingling should be expected in other major basins.

In Nigeria, the Department of Petroleum Resources (DPR) has taken steps to encourage the development of marginal fields, which they define as any field with marginal oil reserves or a field that is low in the portfolio ranking of current operators9. To elaborate, marginal fields are not considered by license holders for development because of assumed marginal economics under prevailing fiscal terms. The DPR has started to address the development of marginal fields by identifying 24 fields with booked reserves that have remained un-produced for a period of over 10 years. An analysis of the 24 identified prospects indicated initial reserves ranging between 5 MMbbl and 40 MMbbl each, with potential to increase this range to 20 MMbbl and 80 MMbbl with the appropriate application of technology. Assuming a subjective average of 30 MMbbl for each of the 24 prospects, and that 15% of these can be exploited by commingling, an additional 108 MMbbl of reserves should be easily exploited from just this handful of opportunities. The Niger Delta shelf has hundreds of these marginal opportunities.

In the United States, stacked reservoirs in the Gulf of Mexico have typically been exploited by sequential development10. Gulf of Mexico shelf operators perceive that intelligent well flow control valves are to be used in the same way, replacing the plug back intervention in the sequential development method with the closing of the downhole flow control valve. Operators have not considered using intelligent well technology for commingling and accelerating or optimizing production.

However, the Minerals Management Service (MMS), recognizing the increasing costs of offshore development in the Gulf of Mexico, is easing the restrictions on the size of reserves to which commingling may be applied. The objective of this change in policy is to maximize the ultimate recovery and prevent waste of natural resources11,12. The evolution of intelligent well technology has played a significant part in this change of policy as a proven enabler for controlled commingling.

Elements Necessary for Controlled Commingling

In order to tackle the concerns and issues of the government agencies and the operators of commingled wells, intelligent well solutions must address the following issues:

  • Flow Control
  • Well Integrity
  • Reservoir Management

Flow Control refers to the ability, at a minimum, to open or shut off a zone or reservoir in a commingled well at will, an unlimited number of times, without intervention. Higher-level intelligent well systems offer the ability to restrict flow or choke each particular interval. The ability to shut-off zones is important to prevent cross flow between reservoirs and to exclude production of unwanted effluent (water, gas). The ability to choke zones is important to balance production between reservoirs, particularly in tertiary recovery schemes. Also key is the operability of the flow control, that is, the reliability and ability to perform the desired function on demand over time.

Well Integrity refers to zone or reservoir segregation, which is affected by the quality of the cement, casing, packers, and flow control valves. Flow assurance and the intelligent well system’s susceptibility to malfunction due to scale, wax, sand, and solids must also be addressed. Finally, the mechanical integrity and reliability of the intelligent well system and the commingled completion must be considered, including testing of integrity and the provision of contingencies if one of the critical elements of the completion fails.

Reservoir Management covers sensing (pressure, temperature), flow estimation and flow allocation, well testing (multi-rate, pressure transient analysis) and Operating Philosophy (flow control plan). These elements are critical for the management of the intelligent commingled well and commingled reservoirs.

Intelligent Well Technology

An intelligent well completion is a system capable of collecting, transmitting and analysing completion, production, and reservoir data, and taking action to better control well and production processes. The value of intelligent well technologies comes from the capability to actively and remotely modify the zonal completions and performance through flow control, and to monitor the response and performance of the zones through real time down hole data acquisition, thereby maximising the value of the asset13.

Elements of Intelligent Wells

The industry generally recognises the definition of an intelligent completion, as described at the 2001 SPE Forum in St. Maxime, France, as one in which “control of inflow (or injection) takes place down hole at the reservoir, with no physical intervention, with or without active monitoring.”

To realize this, the following elements are generally required:

Flow Control Devices. Most current down hole flow control devices are based on or derived from sliding sleeve or ball-valve technologies. Flow control may be binary (on/off), discrete positioning (a number of preset fixed positions), or infinitely variable. The motive force for these systems may be provided by hydraulic, electro-hydraulic or electric systems.

Feedthrough Isolation Packers. To realize individual zone control and ensure segregation of separate hydrocarbon pools, each zone must be isolated from each other by packers incorporating feedthrough facility for control, communication, and power cables.

Control, Communication and Power Cables. Current intelligent well technology requires one or more conduits to transmit power and data to downhole monitoring and control devices. These may be hydraulic control lines, electric power and data conductors, or fibre optic lines. Optical fibres may be installed in a dedicated control line, or may share a control line with a hydraulic line. For additional protection and ease of deployment, multiple lines are usually encapsulated.

Down-hole Sensors. A variety of downhole sensors are available to monitor well-flow performance parameters from each zone of interest. Several single-point electronic quartz crystal pressure and temperature sensors may be multiplexed on a single electric conductor, thus allowing very accurate measurements at several zones. Optical fibres are now widely used for distributed temperature surveys throughout the length of a wellbore and provide temperature measurements for each meter of the well. Single-point fibre-optic pressure transducers are now available, and multi-point or distributed fibre optic pressure sensing is being developed. Downhole flow meters are available based on Venturi systems, or pressure drop correlations across flow control devices. New generation flow meters based on passive optical fibre acoustic sensing are being developed. Other new technologies under development include water cut sensors, fluid density meters, micro-seismic arrays, formation resistivity arrays, and downhole chemical analysis sensors.

Surface Data Acquisition and Control. With multiple downhole sensors providing “real-time” production data, the volume of data acquired can be overwhelming. Systems are required to acquire, validate, filter, and store the data. Processing tools are required to examine and analyse the data to gain insight into the performance of the well and the reservoir. In combination with the knowledge gained from the analysis, predictive models can assist in the generation of process-control decisions to optimise production from a well and asset.

Flow Estimation and Flow Allocation

Flow estimation is the quantification of mass or volume flow of fluids from each zone, layer or reservoir into the intelligent well. This is different from flow allocation, which is the division of a total mass or volume measurement of fluids into shares representing the contribution of each zone, layer or reservoir. Both flow estimation and flow allocation are important in an intelligent commingled well for reservoir management and production accounting.

Flow Estimation and Measurement

Flow estimation is usually derived from measured parameters, most often pressure (such as in an orifice or venturi meter), temperature or vibration. The following methods are typically used in downhole flow estimation:

  • Downhole Flow Meter (Single Point)
  • Venturi
  • Spinner
  • Passive Acoustic Optical Fibre
  • Pressure Drop Across Flow Control Valve
  • Periodic Testing – Inflow Performance Modelling
  • Tubing Performance – Pressure Drop
  • Thermal Modelling – Distributed Temperature

In addition, a measurement or an estimate of effluent composition, particularly water cut and gas-oil ratio must be made for each zone of interest. While down-hole water-cut meters and densitometers are available, suitable estimates of composition can be derived from periodic well tests of individual zones.

Flow estimation by periodic testing and inflow performance characterization is attractive as it can provide a significant amount of information about the performance of individual zones with a minimum amount of down-hole instrumentation. While one zone is being tested, pressure build-ups in the closed in zones can be monitored and analysed in real-time to identify skin, kh, and reservoir pressure. By using multi-rate testing, the production performance of the zone of interest can be well defined and fluid composition can be established. Combined with downhole pressure sensors and continuous monitoring, real-time estimates of flow from each individual zone are calculated from the inflow performance relationship and used in zonal flow allocation. Finally, the testing of individual zones using the intelligent well flow control valves provides an opportunity to confirm segregation of the zones and routinely operate the valves, which may be desirable in wells with a propensity for scaling.