production logging

An international Energy Company & independent engineering company have performed preliminary studies for an In-Line Robot (ILR) Project including: feasibility study, turbine design (with CFD calculations and flow assurance) and Energy Balance Assessments. This Robot will be a tetherless autonomous device capable of travelling with/against production flow to accomplish pigging and inspection missions inside pipelines with minimum production impacts. This is particularly adapted for single line long tiebacks, thanks to regenerative power management but the complexity of subsea architecture, flow conditions & fluids services raises some challenges. The ILR development is programmed over five phases (Feasibility study, Preliminary Systems design & Energy Balance Assessment, Flow Loop Bench Testing, Prototype Testing and Commercialisation). Phase 2 utilised Computational Fluid Dynamics (CFD) simulation models to assess power extraction levels from production flow across various scenarios whilst minimising pressure drop. The results obtained included the turbine CFD models that were coupled to power conversion and storage modules in order to ensure that system drive and power managementwere captured in a closed loop. An operational envelope was established considering the preliminary turbine design simulations as well as the associated energy balance. This paper will present the results to date along with the key design features of the ILR and how the data will be used to verify the operational envelope during the next phase, Flow Loop Bench Testing which is due to start in late 2019. This will provide data to configure and predict operational envelopes of the robot for different flow patterns and fluid types.

The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000 m water depth, including subsea production wells more than 25 km away from the production facility. Producing complex fluids within such a challenging environment required demanding thermal performance of the overall subsea asset with both the problematics of steady-state arrival temperature and cooldown. To do so, the transient thermal signature of every subsea component has been evaluated and correlated into a dynamic flow simulation to verify the integrity and therefore, safety of the system.

A unique design of subsea equipment aims to cover a large range of reservoir conditions. In order to tackle both risks of wax deposit during production and hydrates plug during restart, the whole system was designed to have a very low U-value and stringent cooldown requirements. A dedicated focus on having an extremely low U-value for the Pipe-in-Pipe (PiP) system enables to improve the global thermal performance. The accurate thermal performance predictions from computer modelling were firstly validated during the engineering phase with a full scale test. Eventually an in-situ thermal test was performed a few days before the first-oil to assess the as-built performance of the full subsea network. A well prepared procedure allowed to characterize precisely the subsea system U-value in addition to evaluate the cooldown time of critical components, after installation. The error band was properly assessed to take into account the difficulties of performing such remote measurements from an FPSO.

The different elements of the qualification procedure were successful, validating the demanding thermal requirement of the subsea system. The validation of the thermal performance of the flowline was fully achieved. Detailed analysis of the test results was performed in order to define precisely the U-value in operations. The as-built performance verification, including all elements of the complex subsea network, allowed to validate the optimized operating envelopes of the production system.

A detailed qualification process was conducted in order to fulfill one of the most challenging thermal requirements for a subsea development. Thanks to the precise prediction of the flowline insulation performance, the different reservoir conditions are safely handled. The operating envelope of the production system is finally optimized with the confidence from as-built performances confirmation.

This paper's focus is the advocation of utilising diagnostic data available from digital field devices to help reduce operating costs for end users.

In recent years companies across multiple industrial sectors have invested in improving their understanding of both the historical and live data they produce. The source of the data is specific to the processes but the objective for all remains the same - to use statistical techniques to develop a toolset that can be used to predict performance based on live and historical data.

For the oil and gas industry, the continued adoption of digital device transmitters has increased the volume of data available from instruments such as flow meters, temperature probes and pressure sensors. Typically, this additional data provides information on the integrity or quality of the associated device. However, with the appropriate level of facility and instrument knowledge it is also possible to infer information with respect to the process stream.

Furthermore, this data, if correctly interpreted, can be used to predict maintenance and calibration requirements, resulting in reduced staff effort and shutdowns. The need for physical intervention due to device failure is also reduced, which in turn minimises the potential for accidental hydrocarbon release when a device is removed for repair or replacement.

NEL are currently undertaking research projects with the primary objective of developing definitive correlations between process effects, meter condition and diagnostic data response. The paper provides details of said research, with particular reference to the data science and mathematical techniques currently being trialed for the analysis stage. The techniques, when fully developed, will be metering technology specific and therefore offer a level of insight to end users on facility and meter performance which is not currently available in industry. The toolsets developed will in turn provide the end users with the knowledge and confidence to make cost saving decisions with respect to planned maintenance as well as improving facility efficiency through a more comprehensive understanding of their own data sets.

The North Sea Oil and Gas industry counts over 7,800 wells drilled. The industry is now entering an era of well abandonment and decommissioning. Current barrier verification for P&A requires appropriate pressure testing and includes surface and downhole monitoring.

Globally, Spectral Noise Logging (SNL) has been utilized in many thousands of cases to detect fluid movement behind completion tubulars and/or across a cement barriers.

In Nov 2017, full-scale verification tests were conducted at the International Research Institute of Stavanger (IRIS). These tests were conducted in a controlled environment to verify current technology thresholds. These showed the technique validated the cement barrier integrity during pressure tests and can diagnose channeling as low as 9 ml/min behind the casing. The threshold matrix for different cement defect versus pressure and flow rates allowed the usage of the technology to support the positive qualification of the barrier elements (Dave Gardner, 2019).

Utilizing a purpose-built test assembly of standard oilfield tubular and cement with fitted end caps, a series of pressure tests operations were conducted to identify the pressure and associate leak rates in conjunction with the SNL. The results clearly demonstrated that the logging tool can provide evidence of barrier verification over a wide range of well applications. Barrier qualification requires that three conditions are met; firstly, cement behind casing is in place and not displaying a micro-annulus or any form of fluid movement behind pipe. Secondly, that a cement plug holds pressure and there is also no fluid leak and finally natural shale barriers are active and create a sufficient barrier. Currently, technology is in its 10^th generation, and since the IRIS tests have been used in many wells, covering both onshore and offshore oil and gas wells and wells in highly sensitive environmental areas. On each case the logging operations were used to verify well status before and after the barrier establishment via cement squeeze or section milling and, in several cases, clearly, demonstrate that the barrier status remained ineffective, hidden and further remedial work was required.

This paper discusses the downhole passive noise listening and its spectral analysis technique to prove the effective cement barriers are in place. The concept, methodology and its application which have been successfully tested via yard and field tests are presented in this paper.

The objective of this study was to look at factors that can affect a temperature log and steps that can be taken to improve temperature-measurement accuracy. A new miniature pressure/temperature sensor comes packaged inside a tough small ball capable of traveling to the bottom of a well while drilling and returning with data on board.

In hydraulic fracturing, the use of diagnostic-fracture-injection tests (DFITs) can provide valuable information. This paper offers an analytical model for estimating the transient temperature at a given depth and timestep, for computing the BHP. To achieve optimal production from unconventional reservoirs, it is useful to determine the permeability, pore pressure, and state of stress of rock strata. This paper attempts to describe some of the common problems and to help prevent some common errors often observed in diagnostic fracture injection tests (DFITs) execution and analysis.

With multistage operations becoming the industry norm, operators need easily deployable diversion technologies that will protect previously stimulated perforations and enable addition of new ones. This paper reviews several aspects of the use of in-stage diversion. Significant production gains are being made with hydraulicly fractured wells using diversion to stimulate a higher percentage of the perforations.

In a collaborative project, the possibility of measuring fluid levels in a wellbore by use of distributed optical pressure gauges was conceived, prototyped, field-trialed, and further developed to a point of widespread commercialization. The treatment in a deepwater, frac-packed well with fiber-optic-equipped coiled tubing (CT) and a rotating, hydraulic high-pressure jetting tool achieved successful stimulation of a 500-ft-long frac-packed zone after several previous failures using different techniques. In the past decade, fiber-optic -based sensing has opened up opportunities for in-well reservoir surveillance in the oil and gas industry. In this paper, the authors present a recent example of single-phase-flow profiling with distributed acoustic sensing.

Don't miss our latest content, delivered to your inbox monthly. If you are not logged in, you will receive a confirmation email that you will need to click on to confirm you want to receive the newsletter. The main goal of production logging is to evaluate the well or reservoir performance. Halliburton’s broadened paid family leave program offers eight weeks of bonding leave, which can be taken within 12 months from the date of childbirth or finalized adoption. Groups of students and young professionals generated digital solutions for an abandoned field in Norway using publicly available field data during a SPE hackathon event held in Bangalore, India.

A single-well polymer-injection and back-production test has been performed in an oil and gas field offshore Norway. The objective of the test was to verify at field conditions the properties measured in the laboratory for the biopolymer schizophyllan. Continued enthusiasm in the well-testing segment of the oil industry is apparent. Even though there was a smaller number of presentations among various conferences related to well testing in 2016, there are articles that contribute significantly for the experts and the upcoming generation. The application of high-precision downhole temperature sensors has resulted in pressure-transient analysis (PTA) being complemented or replaced by temperature-transient analysis (TTA).