As gas fields mature and water production increases, understanding and managing the dynamic flow behaviour of the well and production system are critical for maintaining, and even optimising, production. This knowledge could be the difference between a successful and an unsuccessful attempt at re-starting a wet gas well after it is shut-in. When a well is in production, choking the well to optimise stable facilities operation and maintain water production within the water handling constraints of the facilities can be a fine line between achieving continuous stable production and the well ceasing production due to high liquid loading.
This paper describes the successful kick-off and unloading of two high-water producing gas wells within the operational constraints of the offshore facility. Transient multiphase flow models were developed for a platform well and a subsea well to simulate the wellbore flow dynamics during start-up. The models were tested over a range of values for parameters such as reservoir pressure, inflow performance and water gas ratio for different kick-off strategies but always honouring the facility's water surge management constraints.
The outcome of these simulations facilitated the development of tailored bean-up strategies for each high-water producing gas well, which provided a mechanism to engage with key stakeholders and demonstrate confidence in the execution of these strategies. Dedicated procedures were developed and subsequently executed successfully to re-start the two wells with the wells continuing to produce after kick-off and unloading, operating within the water surge management limits of the facility. Similar strategies are being developed for other high-water producing gas wells including those with material sand production.
This paper demonstrates strategic capability to realise additional value using dynamic modelling to kick-off mature high-water producing gas wells through proactive development of mitigation strategies which avoid production disruption.
This paper presents case studies on reservoir and well management of two laterally and vertically compartmentalized Western Australian Triassic gas condensate reservoirs, developed by five multi-zone "smart" wells with sand control, tied back to an offshore platform via a subsea network. In managing assets with such complexity, it is imperative to understand reservoir performance on a zone-by-zone basis. Quantifying performance allows management of flux through downhole sand control systems and optimisation of offtake strategy. The majority of the material published to date on "smart" wells has been focused on completion design optimisation and minimisation of unwanted oil/water production. There are few existing articles about production and reservoir optimisation of high rate gas wells requiring flux management.
This paper showcases how remotely-operated selective completions ("smart" wells with permanent downhole gauges for each completion coupled with subsea flow meters for each well) have been instrumental in facilitating prompt analysis of zonal reservoir performance and thus in yielding insights into reservoir connectivity and allowing optimisation of zonal contributions. Various case studies will be presented showing how reservoir surveillance data is acquired and interpreted to optimize well zone-by-zone production and to manage flux limits on each producing zone. These case studies will include manipulation of downhole valves to provide information for established techniques such as interference testing and P/Z analysis.
Data acquisition and interpretation challenges are highlighted along with fit-for-purpose solutions developed to overcome those challenges.
The insights presented could facilitate better planning of similar systems in the future.
Sok, Robert M. (Australian National University, Digital Core Laboratories Pty. Ltd) | Knackstedt, Mark A. (Australian National University, Digital Core Laboratories Pty. Ltd) | Varslot, Trond (Applied Mathematics, Australian National University) | Ghous, Abid (Applied Mathematics, Australian National University) | Latham, Shane (Applied Mathematics, Australian National University) | Sheppard, Adrian P. (Applied Mathematics, Australian National University)
Ghous, Abid (U. of New South Wales) | Knackstedt, Mark Alexander (Australia National University) | Arns, C.H. (Australia National University) | Sheppard, Adrian (Australia National University) | Kumar, Munish (Australia National University) | Sok, Rob (Australia National University) | Senden, Timothy (Australia National University) | Latham, S. (Australia National University) | Jones, A.C. (Australia National University) | Averdunk, H. (U. of New South Wales) | Pinczewski, Wolf Val
The prediction of hydrocarbon recovery is related to both the detailed pore scale structure of core material and fluid interfacial properties. An increased understanding of displacement efficiencies and overall recoveries requires an ability to characterize the pore structure of reservoir core in 3D and to observe fluid distributions at the pore scale.
Micro-CT imaging is capable of acquiring 3D images of the pore structure of sedimentary rock with resolutions down to the micron scale. This allows the 3D pore-space of many reservoir rock samples to be imaged at the pore scale. The 3D porespace of tighter clastics and carbonate core material includes a significant proportion of microporosity—pores at the submicron scale which are not directly accessible via current micro-CT capabilities. Porosity at all scales can affect fluid flow, production, recovery data and log responses. It is important to characterize pore structure and connectivity in a continuous range across over six decades of length scales (from nm to cm) to better understand these petrophysical and production properties. In this paper we describe 2D and 3D imaging studies of reservoir core via micro-CT coupled with complementary petrographic techniques (thin section, mercury intrusion) and high resolution focused ion beam (FIB) scanning electron microscopy studies of a range of reservoir core. Results are given which illustrate the importance of pore structures at varying scales in determining petrophysical properties.
Microtomography is then used to observe pore scale fluid distributions within the core material. Displacement experiments under controlled wettability conditions are undertaken. The local pore-scale fluid distributions identified via 3D tomographic imaging experiments. These results provide insight into the role of rock microstructure in determining recovery and production characteristics.
Ghous, Abid (Australian National University, University of New South Wales) | Senden, Tim J. (Australian National University) | Sok, Rob M. (Australian National University) | Sheppard, Adrian P. (Australian National University) | Pinczewski, Val W. (University of New South Wales) | Knackstedt, Mark A. (Australian National University, University of New South Wales)
Many aeolian sandstone reservoirs contain significant volumes of recoverable hydrocarbons in intervals where the average lamina thickness is well below the resolution of any logging tool. The variability in petrophysical properties of the laminations increases uncertainties and in turn can lead to an underestimation of the hydrocarbon in place. To date estimates of the Archie exponents m and n in thinly laminated sand reservoirs have been based on simplified model structures. Here we illustrate an ability to visualize the anisotropy in aeolian sands at the pore scale via digital microtomographic imaging, and to measure the anisotropy in resistivity via direct calculation of resistivity on the resultant images.
In this study, 3D pore scale imaging of an aeolian core plug exhibiting fine scale laminae (laminations at the scale of 1-2 mm is undertaken via high resolution micro-CT. The full 3D image is obtained at 3.5 micron resolution. The composite image is made up of a 2000 squared voxel cross section (5 mm squared parallel to the bedding planes and a continuous 3 cm length perpendicular to the bedding plane (9,000 voxels. Strong variation in lamina porosity is observed along the length of the core and more than 20 distinct bedding planes are evident. Individual lamina are analysed for Archie?s cementation exponent m and saturation exponent n. A composite m and n is then calculated both parallel and perpendicular to the bedding planes across varying numbers of lamina.
The values of m and n are found to strongly depend on the relative volume fractions of the different lamina and the orientation of the conductivity measurements. Estimates of m and n based on simple averaging are extremely poor. Predictions based on idealized layering (Kennedy and Herrick, 2003 are shown to underestimate the value of m perpendicular to the bedding plane. Extensions to the measurements at varying relative angles between borehole and bedding planes are given and the anisotropy in the permeability of the core is also measured and reported. The results highlight how digital imaging of core material at the pore scale can be used to obtain important petrophysical trends crucial to accurate formation evaluation.