Rate Allocation Using Permanent Downhole Pressures

Abstract

A common industry practice is to commingle production, either downhole or at the surface. Where multiple layers are present in a reservoir, the most economical development plans often involve commingling the production of all the layers. Commingling production is also cost effective in multiple well scenarios such as on a platform. In these situations, it is challenging to determine the individual flow rates from each layer or well. One operating practice is to isolate each layer or well and determine what fraction of the total production can be attributed to each entity. This fraction is then used to allocate production until individual entity rates can be measured again. Rate allocation methods are often required by regulatory agencies and can require expensive well interventions in terms of delayed production and complex completions such as ‘smart’ wells. Today, many wells are instrumented with permanent downhole pressure gauges which are employed for performance prediction, production optimization, and other reservoir management tasks. In this paper, the use of downhole pressure data is extended to rate allocation. In terms of Darcy's Law, there is a physical link between pressure gradients and flow rates. ExxonMobil has developed a methodology to calculate bottomhole flow rates for each layer or well based on total production and the bottomhole pressure for each layer or well. This paper describes the issues involved, outlines the workflow to address the allocation, specifies the calculations involved, and uses two field examples to illustrate the method. This method shows promise for more accurately allocating production and reducing the required number of well interventions. Introduction Many oil and gas fields commingle oil and/or gas production from multiple wells before taking rate measurements. Another common reservoir management practice is to commingle production from separate stacked reservoirs into a common production tubing. These practices lead to uncertainty in how much fluid is produced from a given well or reservoir since the flow rate measurements are taken downstream of the commingling. Both the production rate and volume information are important for many reservoir surveillance and management tasks. For example, many techniques for estimating the remaining producible oil or gas in a reservoir depend on accurately knowing the amount of oil and/or gas produced from the reservoir in combination with the average reservoir pressure. History-matching oil, gas, and water production data using a reservoir simulator is a common practice in workflows used for making investment decisions such as whether or not to drill more wells. The quality of a history-matched model is limited by the quality of the allocated production data. An additional need for quality rate allocation is that the production volumes for individual wells or reservoirs are often required for regulatory reporting. This is the driving force for most surface well tests that are often costly due to the need for test separators and production down time. Current practices for determining individual well rates often involve shutting-in various wells in order to get single well rate measurements or adjusting production flow so that each well's rate is determined from a test separator. Wells that commingle production from stacked reservoirs often use production logging tools that have spinners, which allow for inferring the rates from each zone. More recently, ‘smart’ completions or downhole flow control valves have been employed. These completions allow for shutting-in certain zones for measurement purposes. Once individual well or zone rate measurements are acquired, an allocation factor is typically calculated for each well based on its relative production to the total. These rate allocation methods lead to increased operating costs and delayed production associated with periods of shut-in. Additionally, these methods cannot account for changes to the ratio of rates in-between the periodic surface well tests. Many times current approaches for determining individual well rates provide rates that are inconsistent with the downhole pressure. For example, the downhole pressures might rapidly increase indicating that the well is being shut-in, but applying a constant allocation factor would allocate production to that well from another well that is not shut-in during the same period.

Application of Experimental Design for Improved Reservoir-Characterisation by Pressure-Transient Analysis

“…During such evaluation, the well is tested at selected rates, which can be correlated to the choke-opening and the FTHP. Taking advantage of the dependence of flowrate on either choke 1 TVD = True Vertical Depth opening or/and FTHP, the resulting relationship would continue to be used for production allocation until individual wells can be tested again to re-calibrate the model (McCracken and Chorneyko, 2006;Hamad et al, 2004). This is the current practice in the asset under discussion.…”

Automatic Detection of Pressure-Buildup Intervals From Permanent Downhole Pressure Data Using Filter Convolution

“…Buildup interval identification (step 3) and the reconstruction of flow rate (step 4) tend to be a time consuming part of the workflow if processed manually, especially when the permanent gauge data is acquired over a long time. Methods for allocating flow rate to individual wells based on pressure measurements have been proposed by several authors [4][5][6] . The method for automatically detecting pressure buildup intervals is provided in some commercial software 7 .…”