Objectives/Scope: XYZ is one of the marginal fields of Mumbai Offshore Basin located in western continental shelf of India. Wells in this field were put on ESP for increasing the production. Regular production profiling with traditional production logging was done in these wells to ascertain the water producing zones if any and do the subsequent well intervention if required. Methods, Procedures, Process: In few deviated wells with low reservoir pressure, low flow rates and large casing size, massive recirculation was observed due to which spinner readings were highly affected. In such scenarios, quantitative interpretation with conventional production logging is highly difficult. Only qualitative interpretation based on temperature and holdup measurements can be made which might not completely fulfill the objective. In one of the deviated wells, massive recirculation was observed due to large casing size. Recirculation on ESP wells is generally not expected due to high energy pressure drawdown exerted on the well. Traditional production logging imposed difficulty in interpretation due to recirculation. Only qualitative interpretation was made from temperature and holdup measurements. Hence advanced production logging tool called Flow Scan Imager (FSI*) with 5 minispinners, 6 sets of electrical and optical probes, designed for highly deviated and horizontal wells to delineate flow affected due to well trajectory, was suggested for quantitative interpretation in such wells suffering with recirculation. Results, Observations, Conclusions: In the next well, production profiling was to be done before ESP installation in similar completion as the last well. Therefore, huge recirculation phenomenon was expected in the well. FSI was proposed in this deviated well with recirculation for production profiling and also for finding out the complex flow regime inside the wellbore. FSI helped in proper visualization of the downhole flow regime with the help of multispinners and probes. Quantitative interpretation was made with the help of FSI data. Also, quantification was confirmed inside the tubing (lesser cross section area) where no recirculation is expected as the mini spinner does not collapse inside the wellbore. In traditional production logging, it is generally not possible due to the collapsing of full bore spinners inside tubing. Better understanding of the flow regime can be obtained with FSI than conventional production logging due to the presence of multiple sensors. Later interventions using FSI results have shown significant oil gains. Novel/Additive Information: FSI was used in deviated ESP wells with recirculation for production profiling, accurate quantification, better understanding of flow regimes and to take improved well intervention decisions.

Ultrasonic imaging based tools have been used for long for delivering high-resolution, comprehensive real-time confirmation of the pipe-to-cement bond quality and downhole pipe condition. However, for comprehensive analysis of cement barriers in challenging scenarios like lightweight cement and for better distinction between different annular materials downhole, a multi-physics evaluation has been developed which combines the measurements taken in thickness-mode with measurements taken in flexural-mode of the casing. Signals from these independent measurements are then processed to provide robust interpretation of solid-liquid-gas behind casing using acquired flexural attenuation and acoustic impedance data. The information provided by the flexural attenuation is related to the state of the material in contact with the casing and does not probe deeper into the cement sheath. However, the pulse radiated by the flexural wave packet into the annulus may be reflected by the third interface, the interface with the formation or outer casing. The inner casing is fairly transparent to this reflected pulse so that it can also be picked by the receivers with significant amplitude. Since this reflected pulse propagate through the thickness of the annulus layer it may bring valuable information about the annulus geometry and material, and about the formation or outer casing geometry. This paper demonstrates third interface echo principles and showcases several case studies for evaluating the outer casing geometry, annular material characterization, casing cut and pull depth suggestion and determining open hole size.

Casings can deform over the life of the well due to various reasons such as changing stress regimes, geological fault and fractures causing pinching, pressure differential created due to production, increased pressure due to injection, squeezing formations such as shale and salt, etc. A detailed casing deformation evaluation can provide insights to the operators in correlating the deformation to suitable reasons in their field. There are various methods to evaluate the innermost casing or tubing using ultrasonic and mechanical caliper measurements but there is no technology available to evaluate outer or second casing deformation without first retrieving the inner casing or tubing. This work introduces and encapsulates the novel methodology of transforming the outer or second casing third interface echo (TIE) response, obtained by advanced ultrasonic and flexural measurement inside innermost casing or tubing, into a 3D wellbore view to suitably visualize and analyze the outer or second string deformations. The work involves measuring the azimuthal radius and thickness of the innermost casing with the ultrasonic evaluation technique and computing the azimuthal annular distance between the two casings using the flexural wave TIE arrival time and its velocity in the annular fluid. The computed values are then combined to generate an array of azimuthal internal radius values of the outer or second casing and is finally converted into a 3D wellbore image for better and straight-forward visualization. To validate the methodology, a shop inspection test (SIT) was carried out where the dimensions of the inner and the outer casing were precisely measured with a mechanical caliper tool. Following that, ultrasonic and flexural measurement tool was run inside the innermost casing to obtain the response of both casings. The comparison showed a close match between the actual values and the measurements. Also, the 3D wellbore shape clearly showed the geometry of the outer string validating the methodology used in the creation of the 3D shape. The work can enable the operators to carry out time lapse outer string analysis on a periodic basis to give them early indications of any deformation in the outer or second string. This novel technique or methodology also has valuable application in plug and abandonment (P&A) where the inner tubing and casing retrieval can be hindered due to outer casing deformation. This technique can also help in designing the right drilling BHA for sidetracking based on the minimum ID of the outer pipe through which slot recovery or side-track has to be performed.

Temperature logs have been used to monitor producing wells since the early 1930s. Normally, analysis of the temperature log is viewed as secondary to that of the spinner flowmeter, which gives flow velocity directly, and temperature is conventionally used only as an indicator of fluid entry/exit with the production logging tool (PLT). The main disadvantage of the PLT is that if spinner flowmeter data are not good due to tool problems, then flow quantification is jeopardized. Additionally, in recent years, the cost of production logging has increased considerably because many wells are now drilled horizontally through the reservoir, and the PLTs must be conveyed on coiled tubing or well tractors, and, in some cases (subsea wells), even this may not be possible. Consequently, alternative technologies become viable if they can be used for flow quantification using just temperature data. This paper presents a new flow quantification model using temperature data acquired using production logging or a distributed temperature sensor (DTS) system. The model presented in this paper can handle multiple production zones with their zonal fluid properties as input to give corresponding zonal flow rates as output. The said model is applicable for single-phase oil and gas producer wells as well as water injection wells in both onshore and offshore environments. There are two modes of flow calculation for each answer product-steady state or transient. The model is integrated into easy-to-use software, and it has options for forward simulation as well as optimization. The forward simulation calculates temperature distribution along the wellbore for any given production profile, which is critical for model calibration for any reservoir. After the model has been validated for a reservoir, it can be used for zonal flow quantification using any temperature survey. The objective of the optimization option is to allow the user to fit the model output temperature curve to a selected temperature curve by means of a genetic fitting algorithm that will adjust one or two user-selected reservoir parameters, such as permeability, pressure, skin, gas-oil ratio (GOR), temperature, or water-cut, until a fit is achieved. The model has been extensively tested against synthetic, literature and field examples and good agreements have been obtained, confirming the robustness of this novel approach.

The Gyda field in the North Sea operated by Repsol was proven in 1980 and the platform started producing in 1990. In June 2017, the Norwegian authorities approved the decommissioning plan for the Gyda field. The decommissioning scope included the permanent plugging of 32 wells in the field. Decommissioning is estimated to cost several hundred million dollars and is expected to finish in 2022. As per the NORSOK standards, each well needs to have confirmed barriers to isolate inflow zones, both for preventing from flowing to the surface and hindering crossflow between them. Cement and creeping formation are both considered to be potentially effective barrier elements. However, the criteria and verification methods used to confirm formation creep and cement as barrier elements are different and hence require an innovative interpretation technique which is presented in this paper. As per the regulations and standards, it is critical not only to evaluate the quality of the circumferential bond for cement and formation creep but also to determine their respective bond length. The most important measurement to accurately determine those criteria in each well is through the ultrasonic and flexural attenuation tool. However, interpretation to differentiate formation creep from cement presents challenges, especially when they have similar ultrasonic properties. Quite often, they coexist at the same depths on different sides behind the casing. Barrier evaluation becomes even more challenging with added complexities such as borehole mud settling due to high deviation, high eccentricity, casing damage, or presence of a microannulus. This paper discusses the techniques and interpretation methods used to accurately evaluate barrier elements, differentiate between cement and formation creep, estimate the tops of cemented areas, and eliminate complex challenges posed by mud, deviation, eccentricity, and wet microannulus sections. Successful and accurate determination of the potential presence and location of annulus barrier elements has been fundamentally important for Repsol to meet the regulatory requirements. A special interpretation technique was established using integrated data evaluation to differentiate creeping formation from cement. This technique successfully determined accurate barrier intervals, helping to meet all the regulatory requirements. The processes and methods have been audited and evaluated by the Petroleum Safety Authority Norway.