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.
In this paper, we discuss the importance of production logging in tight gas reservoirs due to the large number of commingled entries that are typically associated with tight gas wells. We discuss the challenges associated with obtaining high quality production log data in tight gas reservoirs and the subsequent production log interpretation. Along with addressing these challenges, some initial production logging results are presented that highlight the importance of geology. These results include:Most of a well's production comes from a few zones,Some observed production rates are substantially higher than anticipated based on matrix properties, andIn a few cases, sands that can be locally correlated between wells may be associated with anomalously high production rates. Introduction Interest in unconventional resources is increasing in order to meet the world's growing demand for energy. Unconventional gas resources include tight gas, shale gas, and coal bed methane. The National Petroleum Council (Raymond et al. 2007) reported that there are an estimated 4,024 Tcf of global natural gas resource in tight gas reservoirs and 8,225 Tcf in coalbed methane reservoirs. This paper will focus on tight gas, which is often defined as gas in low permeability rock that must be stimulated in order to obtain commercial flow rates. Tight gas reservoirs pose many challenges to both reservoir engineers and geoscientists. Many of these challenges result from the poor reservoir connectivity due to the low permeabilities and the limited size of some of the sand deposits. Some interesting questions for optimal tight gas development include:How is the reservoir depleted? andWhat geologic features impact water and gas productivity? Since many tight gas developments involve stimulating multiple zones and commingling the production in a common wellbore, understanding the wellbore inflow profile is required to answer these questions. (In this paper, zones are defined as perforated and stimulated sandy intervals identified from their gamma ray signature. Zones may consist of one or more closely spaced sands.) Inflow profiles are traditionally obtained via production logs. However, obtaining high quality production log data in many tight gas wells is difficult due to the large number of closely spaced zones, relatively low flow rates, and water-gas slugging. In the next section, we will provide a field overview. After the overview, we will discuss the challenges with production logging in tight gas wells. The following section will provide some initial results that highlight the importance of geology in the Piceance Creek Unit. The last section will summarize the results. Background on the Piceance Field and Development The Piceance Creek Unit (PCU) was formed in 1940 and is located in northwestern Colorado approximately 15 miles northwest of Rifle. Figure 1 shows the location of the PCU (outlined in black). Recent completions have targeted the Mesaverde formation (see Fig. 2). The development of the Mesaverde in the Piceance basin poses many challenges due to its geologic complexity, low permeability, and thick gross interval.
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