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This paper discusses the effectiveness of the third-generation (Gen3) Production Logging Tool (PLT) technology which incorporates the use of co-located digital sensors for simultaneous acquisition of flow data. Case studies are provided which demonstrate that this technology is a step-change in the application of digitalization to a down-hole sensor platform which provides the most accurate characterization of the flow condition at each depth surveyed. The resulting data allows for much improved processing which is also described. The probabilistic interpretive model used in the processing has been updated to incorporate this and future developments in PLT architecture. Planning, execution, and analysis of data for the wells is described in detail. Due to the significantly shorter configuration of Gen3 tools, safety at the wellsite is enhanced by allowing for a much-simplified surface rig-up. One well was logged in surface readout (SRO) mode while data in the other two were recorded in the downhole tool's memory for retrieval at the surface at the end of operations. This flexibility in logging modes optimizes operations by addressing the needs of the operation teams. Three Deepwater Gulf of Mexico producers logged with the Gen3 PLT are described. In each case, a clear path forward is provided for optimal management of the reservoirs through effective production management. The first generation (Gen1) of PLT provided a single discrete measurement for each sensor along the tool assembly's length, resulting in long tool assemblies and measurements taken at different points along the flow path. This approach had several drawbacks: long toolstrings, point sensors only provided a measurement at a single point in the cross-section of the flow, and measurements were not acquired simultaneously at each depth logged. The second generation (Gen2) of PLT was an improvement as sensors were arranged as an array enabling multiple measurements to be made at a single depth but were still long and not all were optimally arranged to capture data in the path of flow. The Gen3 PLT is one-tenth the length of the Gen1 versions and roughly one-third of the shortest Gen2 tools. Digitization allows for direct measurement of flow conditions and rapid interpretation of results. In multi-phase flow and deviated wells, the co-location of sensors in a spatial geometry provides the optimal information with which to create a fully accurate picture of the downhole flow.

A variety of technologies have been used to address the challenges faced by Production Logging (PL) in high deviation and horizontal wells.Different configurations of array sensors have been deployed in these environments, to address well work objectives. There are situations where it is hard to differentiate between qualitative and quantitative answers. The question is how quantitative is high angle and horizontal PL data.Multiple datasets were studied and increased value can be added to array raw data by improvements to processing and interpretation. There is a need to differentiate between data acquisition and data processing and interpretation for high angle and horizontal PL. This paper describes a probabilistic approach developed to combine sensor responses into a quantitative solution. Individual sensors from a multiple array production suite can be used in combination with centralised (conventional) sensors to address reservoir conditions and well access challenges. Difficult well completion and rig height limitation increase the complexity level in such environments. This probabilistic approach is applied in a complex North Sea example to gain greater reservoir understanding with a rapid turnaround.

The Pinedale anticline is located in the Green River Basin of Southwestern Wyoming, USA. The field is the largest tight gas discovery for the onshore region of the United States in the last twenty years (Robinson and Shanley 2004). Gas production is from very tight, stacked clastic reservoirs that are Upper Cretaceous in age, with productive intervals in excess of 6000 feet. The large productive intervals require multiple hydraulic fracture stages to complete. Time-lapsed production analyses are performed to optimize well spacing and to characterize the gas bearing reservoirs. Production logs are also run to determine the effectiveness of the hydraulic fracturing and to identify water entry points that may lead to premature completion failures. Typical wells produce relatively small amounts of water, usually less than 5 percent by volume. It is nearly impossible to detect such small watercuts with conventional methods of production analysis. However, a probabilistic production analysis method simultaneously modeling flowmeter and temperature can take advantage of the high contrast between the heat capacity of gas and water and therefore provide good estimates of the water and gas production profiles, even in small watercut wells. This paper describes the technique used to improve the production flow profiling, supporting its assertions with case study results. Introduction Productive intervals in the field are stacked-lenticular tight sands with porosity ranging from 6 to 12% and permeability in the submicrodarcy to 20 microdarcy range, with an average value of 4 microdarcies. Water saturations vary from 30 to 60%, with comparably low water production. Condensate ratio with an API gravity of 52 is 8 to 10 bbl/MMscf (Eberhard and Mullen 2003). Numerous faults exist in the region, adding to the complexity of the reservoirs and creating over pressured gas zones in wells whose nearby offsets encounter normally pressure zones at similar depths. Pore pressure variability with depth does not follow a linear pattern, with intervals in the normal range bounded by layers in the geopressured zones. For this reason, individual production intervals must be hydraulically fractured in isolation with other intervals to assure effective treatment. Such complexities in the fracturing methodologies require an effective method of assessing flow contribution, both by phase and flow rate, of each productive layer. Additionally, the method used to estimate layer properties in multi-layer low permeability gas reservoirs (Spivey 2006) requires that accurate flow contribution be measured for each productive layer. Since the method requires multiple measurements over time as an input to the history match, consistent measurements and production log analyses are an absolute necessity. The combination of accurate production logging analyses and layer property determination provides the reservoir and production engineering teams with much more precise data than surface production data alone, maximizing the effective management of resources. With the cost of proppant representing as much as 30% of total completion cost (Huckabee et al 2005), accurate production analysis of the fracturing effectiveness can enable significant cost savings. Production Logging Methodology A typical completion (figure 1) consists of up to 24 frac stages each of which may have six perforated intervals ranging from 2 to 6 feet in length. Perforating shot density is 3 shots per foot. A 7 inch protection casing is set 600 feet from TD, with 4 ½' casing set from TD to surface. Flow-through composite fracture plugs (Eberhard, et al 2003) are used to isolate hydraulic fracturing treatments, then drilled out prior to production.

In well and reservoir management, optimum and accurate determination of multiple phase well-bore fluid entry is required to make decisions on water/gas shutoff opportunities. This can only be possible if good quality production log data is acquired and most importantly if accurate data analysis is done. This paper examines the drawbacks experienced using the conventional production log analysis methods and its associated risks. It will introduce an alternative probabilistic approach leading to more accurate results. The results of a case study will also be presented where a cement water shutoff was planned and executed based on the result of conventional analysis. It will also show how the results of the probabilistic approach would have saved the cost of the cement water shutoff