Production logging has been traditionally used for zonal quantification of layers for identification of most obvious workover for water shut off, acid wash or reperforation candidate identification. The basic sensors help in making some of the critical decisions for immediate gain in oil production or reduction in water cut. However, this technology can be used in a non standard format for various purposes including multilayer testing to obtain layer wise permeability and skin factor using pressure and flow rate transient data acquired with production logging tools. This is very crucial and complements the present wellbore flow phenomenon to better understand relative zonal performance of well at any stage of its production. In addition, production logging along with the pulsed neutron technique is very crucial to evaluate the complete wellbore phenomenon, understand some of the behind the production string fluid flow behaviors. Another major concern in low flow rate wells is recirculation, causing fall back of heavier water phase while lighter phase like oil and gas move upwards. This well bore phenomenon renders the quantification from production logging string, and this in extension also prevents any comprehensive workover decisions on the well because of the risk involved. Oil rate computation from hydrocarbon bubble rates becomes very critical in such scenarios to bring out the most optimal results and enhance confidence in workover decisions. Another key concern in any reservoir is to evaluate the productivity Index; this is even more critical once the field is on production. It is essential to determine the performance of various commingled layers and reform the Injector producer strategy for pressure support or immediate workover. Selective Inflow performance is a technique used to identify the Productivity index of various layers in a commingled situation. This paper elaborates on various non conventional uses of production logging from the western offshore India.

A field in western offshore India proved to be a major hydrocarbon-bearing structure, but wells in the field gradually declined in reservoir pressure and production when they were self-flowing. To improve recovery, water injection was performed, which almost doubled the field production. However, water cut eventually increased drastically, thereby reducing oil production. To curtail increasing water cut and improve oil recovery, a tertiary recovery method was sought. After closely studying various recovery methods, simultaneous water and gas (SWAG) injection was proposed in which a predefined mixture of produced gas and water was injected to improve oil sweep and reduce residual oil saturation by oil swelling, ultimately increasing oil recovery. However, to practically observe field suitability and feasibility of the SWAG method, a pilot project that included four injectors and one producer was launched. Efficiency of SWAG injection increases as a result of the consistent gas and water fine bubble flow regime developed in the wellbore, depending on casing size, tubing-shoe distance from perforation, and deviation. To evaluate this efficiency, production logging with optical probes to detect gas holdup was proposed in three injectors with different casing sizes and deviations. The existing wellbore flow regime from results of production logging were observed and compared with respect to favorable flow behavior to understand the effect of these factors on SWAG injection effectiveness. We found and suggested the deviation and casing-size configuration that was deemed optimal. This was the first time production logging was used in India to evaluate the SWAG injection wellbore flow regime, and the method proved effective. The results are to be used for full-field SWAG injection implementation to improve overall field recovery.

Objectives/Scope The Raageshwari Deep Gas Field in the Western India, operated by Cairn, Oil and Gas vertical of Vedanta Limited, is a tight gas laminated reservoir with an average permeability of 0.1mD and a gross pay interval of ~700 metres. It is characterized by numerous packets of good porosity with high gas saturation. When the successful development of a reservoir is based on the ability to accurately model and install hydraulic fractures, verification of the fracturing models is critical. Verifying the fracture height is one way to reduce the uncertainty in the model results. This paper describes how the Pulsed Neutron Logging (PNL) was used to determine the fracture height in near vertical well by detection of boron, a primary constituent of borate based crosslinked fluid systems. The discussion will also include the benefits of quantifying the actual fracture height such as determination of the required number of stages and calibrating the fracturing simulator. Methods, Procedures, Process The PNT log was designed as an alternative to temperature and radioactive tracer logs and has been successfully used for the identification of channels in the cement sheath surrounding the casing, fluid movements, gas migrations etc. in both production and injection wells. PNL is used to track the movement of a saline solution of borax and water by measuring changes in the capture cross section of an interval caused by the injected borax. The above technique involves running a base PNL pass, injecting a boron solution into the interval, and then making the post injection PNL passes. The boron solution generates a significant change in logging tool response, enabling the tool to identify solution movement inside and outside the casing. The completion strategy in Raageshwari incorporates hydraulic fracturing through near vertical 3-1/2" monobore wells placed in 6" hole. Therefore, 8-10" depth of investigation of the PNL is sufficient to measure the frac height in the near wellbore area by measuring the boron present in the frac fluid in the fracture and the area adjacent to the fracture. Temperature logging was also performed in tandem with the PNL as an additional means of estimating fracture height. Results, Observations, Conclusions The pre-and post frac PNL survey responses were sufficiently different to enable estimation of the fracture height and the results were comparable to the heights obtained from the temperature logs. Knowing the fracture height provided an additional constraint which improved the fracture modeling. This technique is a cost effective way of determining fracture height without the need of pumping any additional hazardous (radioactive) or expensive materials. Its main advantage over temperature logging is its lower sensitivity to delays in the post fracture logging process. Novel/Additive Information The use of PNL for the fracture height determination from simple detection of boron present in the borate based cross linked fluid.

Field XYZ located in the western offshore India is a multi-pay, multi-layered heterogeneous Carbonate reservoir having lateral discontinuities. Discontinuous layers and scale deposition and near well bore damage have led to multi-dimensional problems related to both upper and lower completions reducing ultimate field recovery. Workover attempts like re-perforation, additional perforations and plugging, artificial lift by electrical submersible pump (ESP) and secondary recovery by water injection were implemented to maximize the field recovery. However, any work over had only short term impact on production increase.Also, water injection and ESP performance were inefficient. Production History showed cyclic decline in production with time. Identifying and locating the layers' discontinuities became crucial in candidate selection and design of efficient injection pattern, artificial lift, completion and work over in existing and new infill wells. The following case study presents a workflow involving multi well geological, petro physical and time lapse formation pressure data and production logs to identify and locate lateral discontinuity within a pay of the field. As a result, the reservoir pressure support attempts using water injection methods were proved to be suboptimal. Furthermore, this workflow has been successfully implemented for identifying location of infill wells and candidate selection and design of wells to be completed with ESP. Seven future candidates for ESP were recognized. Additionally, locations of three new infill wells are identified and a strategic layer wise completion was designed and executed. Implementation of the results increased production from the field by 27%.

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