No abstract

A major exploration and production (E&P) company is acquiring a significant number of multiphase production logs a year for reservoir management. It is anticipated that this number will increase, when these deviated and horizontal wells start to produce water. It is more challenging when these wells become dead due to downhole communication between an aquifer and the objective reservoir resulting in excessive downhole water dumping. The strategy, therefore, is to run advanced production logging tools (APLT) integrated with the pulsed neutron logging tool (PNLT) to provide velocity along with holdup maps across the diameter of the borehole from an array of sensors and water velocities inside the wellbore or the annulus, respectively. The combination between APLT and PNLT data provides accurate detection and quantification of water zonal contributions. The aim of the three case examples presented in this paper is to facilitate detecting the leak point and assembling the inflow profiles. The first example is an open hole completion. The logging data showed 1000 bbl of down-flow movements in the tubing-casing annulus (TCA) starting from the shallow aquifer. The second well was completed with an inflow control device (ICD). Water dumping was observed from the leak over the blank pipe down to the screen interval, which is also supported by temperature deflection. The third example is a cased-hole perforated completion. An integrated logging approach yielded reliable results in detecting the water entry interval, and the water entry was identified from the perforated section flowing upward to the casing leak. This detected crossflow in the mentioned examples at shut-in conditions was the reason that the wells were dead. The established integrated logging solution and field examples showed evidence that a leaking interval was suspected to be responsible for high water cut, reducing well performance and killing the wells. The source of water production identified provides the justification for a workover to isolate the water entries, secure the objective reservoir, and revitalize the dead well.

Long horizontal wells in naturally fractured carbonate reservoirs often exhibit very high water-cut within months of production because of the early arrival of water from natural fractures. Passive inflow control devices (P-ICDs) have been used globally to balance influx, delay water or gas breakthrough to prolong well life. However, some wells have continued to experience high water-cut despite the control measures. Image log review has revealed the uncertainty is in the identification of fractures and its conductivity networks. Two additional zonal control technologies are presented in this paper: on/off ICDs and intelligent (IC) or smart completions in comparison. A software-based 3D reservoir model was built to represent a horizontal oil-producer in a fractured carbonate reservoir penetrating a thin oil rim. The first model simulated well production performance in a well with on/off ICD. Intervention was replicated in time (i.e., taking longer) to shut-off ICDs. The second model evaluated production forecast over the same period for the same well, this time equipped with an IC in the open hole (OH). Actions in this case were taken right away from the surface (i.e. without downhole intervention) to identify and restrict or shut-off intervals with water breakthrough. Time-lapsed 3D reservoir model calibration is possible with ICs as they provide real-time downhole pressure and temperature across each interval. The timely control of zonal valves from surface actuation reduced production of water or gas. On/off ICDs, on the other hand, necessitated scheduling a production log (PL) to confirm the interval of water or gas breakthrough and performing coiled-tubing (CT) intervention to shut-off the problematic zone. Intervention comes at cost of interrupting well production and reducing net oil recovery. A simplified cost-benefit analysis of both cases showed that despite a higher initial capital investment in ICs, well operating costs were substantially lower with higher oil recovery. In IC solution, costs for running production logs and intervention tools were eliminated and so was the risk of losing these tools in the hole and the loss in production during the intervention period. Continuous monitoring of downhole pressure data helped reservoir characterization and prediction of reservoir production behavior without compromising production on-stream time. A comparison of different reservoir flow control devices suggests that ICs are the optimal choice in some fractured carbonate reservoir conditions. They provide real-time monitoring of each producing zone and surface control of the flow control valve (FCV) settings in real-time as reservoir performance changes. They enable production testing evaluation—without production logging and interventive shifting with CT, i.e. to determine the source of water entry and optimization of multi-zone production without downhole intervention.

Although various logging challenges in highly deviated and horizontal wells have been addressed in many previous studies, only a few investigations have focused on emulsion diagnosis and multiphase production log (MPL) solutions in such difficult conditions. The emulsion discussed in this paper is water-in-oil emulsion, in which water is present in the form of droplets dispersed in oil. This is generally expected to happen in a high velocity, turbulent flow regime, and in a low density contrast between oil and water. The impact of water emulsion is the inability to identify and quantify water entries using the standard holdup measurement arrays, because the water droplets have the same conductivity as oil and travel at the same velocity as oil, regardless of well deviation.A novel workflow and methodology were established for successful diagnosis of this emulsion downhole to be able to perform inflow profiling for these problematic wells, using information from different sources of data: multiphase production logging tool (MPLT), pulsed neutron logging tool (PNLT), and surface fluid sampling. The workflow includes job preparation, real-time monitoring during logging operation, and post-job data interpretation.The optimized workflow was applied to field examples for successful diagnosis of the emulsion and the integrated logging solution to overcome this challenge in horizontal wells. This led to the determination, with high confidence, of the downhole flow profile and to the accurate quantitative identification of the source of water production. The information can then be used to plan suitable well intervention, without which the reservoir and/or field development could not be optimized.

Sustaining long-term well production in deep gas wells can exhibit unique challenges in shaly sands. The wells can be vertical or slanted gas producers and completed with stand-alone screens. The challenges were to quantify zonal contributions, detect smaller water entries on these high-temperature deep gas wells where reservoir heterogeneity with different depletion layers can result in strong crossflow, and evaluate the existing sand formation behind the screen to avoid restricting the wells’ productivity. This paper describes an integrated approach taken to overcome these challenges with three field examples. A multiphase production logging tool was run to measure the water flow together with the gas contributions across the stand-alone screens on these wells. A pulsed neutron logging tool was run to identify the small amount of water by using a water flow log model. To assess and evaluate the conditions of sand behind the screens, two independent logging techniques were implemented: silica activation and carbon–oxygen inelastic silicon yield techniques. A combination of pre-job planning, an optimized logging program, and proactive real-time monitoring allowed a safe logging operation by drastically minimizing the time exposed by the tool downhole in a high-temperature environment. Early monitoring of water production is important to achieve optimal well productivity and reduce the possibility of the hydrate formation obstructing the flow lines. The source of sand production and the quality of the packing behind the screen were also evaluated. This best practice was established in the field and will greatly improve well deliverability and maximize gas field production.