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One of the most common challenges in oil and gas production today is the multiphase production from a well with a high-water ratio continuously increasing along with the natural depletion of reservoir pressure. Wells in Ujung Pangkah (UP) field, generally completed in order to segment the flow. This is achieved by using Inflow Control Device (ICDs) and Sliding Sleeve Doors (SSD). This completion strategy aims to overcome the water continuity problem that creates a steeper drop in oil or gas production. As part of reservoir surveillance and water source identification, typically, a Production Logging Tool (PLT) is utilized as the standard technology. Nevertheless, it requires an equipment unit to convey this PLT technology into production tubing up to the target depth. To optimize production in wells completed with horizontal with multi sections, determination of water sources is essential to make decisions on intervals to isolate in order to minimize water production rate. SAKA Energi Indonesia, as the operator of Pangkah PSC, has applied another approach to this water source identification known as permanent installed chemical tracer.

Considering the dependency on equipment, tool, and cost of running conventional PLT technology, SAKA has implemented chemical tracers embedded into each well completion's ICDs. The tracer technology was installed in WPA-X and used twice, to identify the ICD sources responsible for the incoming water. The installed chemical water tracers (one unique tracer chemical per inflow section) can detect that specific ICD's contribute to flow – simply from pure mass-balance considerations. Furthermore, if the well is shut-in and restarted, the time-evolvement of tracer signals and differences in arrival-time for individual signals can be used to assess the zonal inflow contribution across separate inflow points along the well.

Compared to other methodologies (e.g. production logging tools), the tracers can provide results during unrestricted flow (i.e. without any tool affecting the flow). Other key benefits of this permanent solid tracer in the well are intervention-less activity that reduces cost and continuous reservoir monitoring. For short-term advantages, the inflow tracer data could provide quantification of each zone contribution, water break-through identification, and indirectly get information on packer integrity and other completion design performance. For mid-term benefit, the result could drive an action plan to eliminate water production in WPA-X. This tracer technology is a flexible technology with several applications to support specific decisions over a long time period in the well's life.

The use of classical production logging tools (PLT) for the purpose of inflow profiling has occurred for decades in the Greater Ekofisk Area (GEA) wells. Recently, several of the newly drilled wells have been completed with inflow tracer (IFT) technology to trial an alternative means of acquiring an inflow profile. The results and lessons learned from employing both methods on the 2/7-S-35 well in the Eldfisk field are shared in this paper.

The IFTs are directly installed on the outside of the reservoir liner adjacent to each sleeve. The initial acid stimulation is key for releasing and displacing the tracers into the reservoir. Upon production start, the tracers are flowed back continuously with the produced fluids and sampled at surface. The samples are analyzed, interpreted, and a continuous inflow profile for the well is generated.

The inflow profiles derived from both IFT and PLT methods revealed differing results in the subject well. The most notable deviation was in the bottom of the well (Hod formation) where the PLT spinner did not show flow while the IFT showed a significant flow contribution (30% of total). Upon closer analysis of the PLT run, the temperature sensor data suggested flow from the bottom of the well which conflicted with the spinner sensor data. Overall, the IFT data and PLT temperature sensor data confirmed flow from the Hod formation which was also consistent with performance from offset analog wells.

Both methods offer an inflow profile solution at a similar cost but come with their own strengths and weaknesses. Careful design and application are recommended to increase the chances of capturing a representative inflow profile for a given well. The novelty of this paper is in the implementation of the patented rate-dependent method for generating IFT-based continuous inflow profiles for the subject well. The IFT provided a more credible inflow profile than the PLT and this data supported the decision to drill a dedicated well to further explore the Hod formation potential in the Eldfisk field.

In order to quantify and monitor inflow along the deepest 5,000 ft of a 45,000 ft extended-reach drilling (ERD) well, a (non-radioactive) permanent inflow tracer system was installed, sampled, and analyzed. The tracer technology was piloted as a supplementary downhole data source to the existing practice of intervention-based production logging due to current limitations of intervention accessibility. This application aided in assessing contribution of the lateral segment within a 1-md reservoir quality rock and determining clean-up efficiency.

The deployed lower completion is a 6⅝-in limited entry liner, segmented by packers with design specifically optimized for bullhead stimulation. To meet well objectives, the design of lower completion, along with placement of tracer carrier subs, was geometrically optimized based on expected flow streams. Final deployment included 3 externally vented tracer carrier subs per compartment with optimized spacing, each mounted with a chemically different tracer for both oil and water. A total of 21 distinct signature tracers were deployed per phase within the 7 compartments with compartment length ranging from 681 to 782 ft. In addition, liner is equipped with dissolvable plugged nozzles for efficient mud cake breaker displacement.

Upon activation, the well was flowed for 2 weeks at maximum rate for efficient clean-up before shutting it for 1 week for tracer concentration build up. The well was then flowed, and 106 samples were taken in a decreasing sampling frequency. A subset of 17 samples were selected for analysis – the collected samples were oil with no traces of water. Analysis of the tracer concentration with time showed the arrival of all 21 oil tracer signals and peaks, followed by a decreasing trend towards steady state levels. Results indicate that all reservoir zones contribute to oil production and that all zones have responded similarly in terms of the tracer profiles. This suggests a homogenous reservoir pressure drawdown across all zones. Furthermore, this indicates that reservoir zones cleaned-up efficiently and demonstrates effectiveness of an applied mud cake breaker displacement technique. The tracer results indicate minimum formation damage – in line with expectations, as the target area is a homogeneous 1-md rock quality with uniform reservoir pressure. Using the tracer data, a quantitative interpretation was performed, by use of the so-called flush out tracer transport model. The methodology was successful in determining relative flow contribution per traced zone. Results shows a uniform relative inflow contribution ranging from 4 to 6% per zone. The chemical inflow tracers were deployed in a well with world-record length of 6⅝-in lower completion at 29,243 ft, beyond current accessibility limits of rigless intervention. Also, the well is ranked 5th worldwide (as of time of this writing) in terms of longest well at 45,000 ft, thus making it a world-record in terms of the deepest deployment of chemical inflow tracers.

This paper presents the integration of two surveillance technologies, inflow & inter-well tracers in an Abu Dhabi Offshore field, for the first time to monitor a complex multi-layered reservoir with early stage water injection. Inflow tracers are chemicals with unique identities, installed into the lower completions that penetrate different layers in the reservoir. Inter-well tracers are also unique chemicals injected into injection wells. Tracer technologies allow non-electric wireless monitoring of the reservoir for many years while reducing cost and operational efficiency. In both technologies, data capture requires to fluid samples to be collected and analysed to detect the unique tracers in the production wells. Inflow tracers provides both qualitative and quantitative estimates of zonal flow as well identifying the source of water breakthrough. Inter-well tracers introduced in the injection wells can identify the primary flow paths and rate of movement of injected fluid in the reservoir. This information can be used to evaluate water channelling and improve water flood conformance plans to maximize sweep efficiency.

The planning and design stage included a selection of pumpable inter-well tracers, volume calculation and breakthrough time simulations to determine the tracer mass required to meet the monitoring objectives. On the other hand, inflow tracers were designed to account for high temperature and highly acidic stimulation fluids and placed along the producing intervals in the lower completion. Quantification models will be utilized to quantify the zonal influx while accounting for expected cross flow. The execution plan is defined by the optimum production and injection rates, equipment and lab test requirements, and optimized field sampling schedule for transient and steady state flow campaigns.

The co-implementation of both tracer technologies in the early stage of waterflood development offers unique ability to monitor the reservoir, eliminating the need for expensive, complicated offshore logistical arrangements for time-consuming wireline interventions to manage the reservoir more efficiently and maximize recovery.

In 2003 the mature gas field K12-B was selected as a demonstration site for offshore injection of CO2. The initial project was aimed at investigating the feasibility of CO2 injection and storage in depleted natural gas fields on the Dutch continental shelf, with the objective to realize a permanent CO2 injection facility. Over the years many different aspects related to CO2 storage at K12-B have been researched, most of them widely applicable to other CO2 storage sites as well. CO2 injection and related research projects involving K12-B have continued until 2017, completing a period of almost 15 years of CO2 injection. This paper presents an overview of the most relevant and memorable research topics, their related activities and results.

The K12-B gas field, is located in the Dutch sector of the North Sea, some 150 km northwest of Amsterdam. It was developed and operated by predecessors of the current operator, which since 2017, is Neptune Energy Netherlands B.V. K12-B has been producing natural gas from the Permian age, Upper Slochteren Member (Rotliegend) since 1987. The natural gas produced has a relatively high CO2 content (13%) and the CO2 is separated from the production stream on site, prior to gas transport to shore. The CO2 used to be vented into the atmosphere but from 2004 on it has been injected into the gas field above the gas-water contact; at a depth of approximately 4000 m. K12-B was the first site in the world where CO2 has been re-injected into the same reservoir from which it originated. The average CO2 injection rate could reach 30,000 Nm3 CO2 per day, which is approximately 20 kt per year.

This paper presents an overview of the results and lessons learned of the multiple measurements campaigns and numerous research projects related to the CO2 injection at K12-B since 2004, performed by the operator and TNO. The research ranged from the investigation of top side and well equipment to the behavior of the gas field to social, environmental and risk assessment aspects. This paper will take you through our journey where we encountered anomalous tubing thicknesses, abnormal downhole injection pressures and surprising chemical evaluations. The paper will present how we learned more and more about the reservoir itself through the analysis of tracer chemicals breaking through, continuous extensive reservoir modelling, geomechanical modelling and even the actual back production of re-injected CO2.

This paper shows what valuable knowledge and information the CO2 injection project at K12-B has produced over the years. CO2 injection at K12-B was stopped when end 2017 the separation of CO2 at K12-B itself came to a halt. Without the active separation of CO2 on site there was no supply of CO2 anymore, which could be injected into the reservoir.

The initial development of inflow tracers was initially designed to provide qualitative information about identifying the location of water breakthrough in production wells. The proof of concept and application for water detection, initiated the development of oil tracers for oil inflow monitoring. Different approaches to install them permanently within a completion component were used, to provide risk free, reliable production monitoring without the need for intervention. Installing unique chemical tracers that are embedded in polymer materials in sand screens or pup joints, along select locations in the lower completion was to correlate where the oil and water is flowing along the production interval and how much. Innovation in the chemistry and materials designed to release to a target fluid (oil or water), enabled non electric wireless monitoring capabilities for many years of longevity in harsh well conditions, such as high temperature and highly acidic stimulation fluids. The evolution of inflow tracer signal interpretation, qualitative and quantitative interpretation workflows using models have also provided valuable insight to inflow characterisation. The latter can provide zonal rate information like wireline conveyed production logging tools, by inducing transients through shut in's or rate changes to create tracer signals that are transported by flow to surface and captured in sample bottles for laboratory analysis. A model based approach to match the measured signals with proprietary models through history matching workflow has also been developed. There are hundreds of well installations utilising inflow tracing monitoring technology today, where the majority have been in open hole completions in both sandstone and naturally fractured carbonate reservoirs on land, offshore environments in both platform and deep water sub-sea environments producing through long tie backs to FPSO's. The monitoring sensors are adaptable to most completion types in conventional and unconventional reservoirs. In most cases, inflow tracers can monitor clean-up efficiency, any subsequent restart and steady state production. Practical case studies will discuss the development of robust and reliable inflow tracer and technology and how operators have applied it over the past decade in a chronological order.

Tracer technology has evolved significantly over the years and is now being increasingly used as one of the effective monitoring and surveillance (M&S) tools in the oil and gas industry. Tracer surveys, deployed as either interwell tests or single-well tests, are one of the enabling M&S technologies that can be used to investigate reservoir connectivity and flow performance, measure residual oil saturation, and determine reservoir properties that control displacement processes, particularly in improved oil recovery (IOR) or enhanced oil recovery (EOR) operations.

As part of a comprehensive monitoring and surveillance program for a GAS-EOR pilot project, an interwell gas tracer test (IWGTT) was designed and implemented to provide a better understanding of gas flow-paths and gas-phase connectivity between gas injector and producer pairs, gas-phase breakthrough times ("time of flight"), and provide pertinent data for optimizing water-alternating-gas (WAG) field operations. Additional objectives include the detection and tracking of any inadvertent out-of-zone injection, and acquisition of relevant data for gas reactive transport modelling. Four unique tracers were injected into four individual injectors, respectively, and their elution were monitored in four "paired" updip producers.

In addition to the reservoir connectivity and breakthrough times between the injector and producer pairs, the results showed different trends for different areas of the reservoir. The gas-phase breakthrough times are slightly different from the water tracer breakthrough times from a previous inter-well chemical tracer test (IWCTT). Residence times for the tracers indicate different trends for three of the injector-producer pairs compared to the last pair. These trends reflect and support conclusions regarding reservoir heterogeneities also seen from the previous IWCTT, which were not anticipated at the beginning of the GAS-EOR pilot.

This paper reviews the design and implementation of the tracer test, field operational issues, analyses, and interpretation of the tracer results. The tracer data has been very useful in understanding well interconnectivity and dynamic fluid flow in this part of the reservoir. This has led to better reservoir description, improved dynamic simulation model, and optimized WAG sequence.

When analyzing well performance in carbonate reservoirs, the traditional approach usually requires the best practices from pre and post stimulation analysis. Most techniques require an understanding of production performance, which can be divided into two categories. The first is related to reservoir performance away from the wellbore i.e. permeability, fracture network, reservoir pressure, boundaries and secondly, the near wellbore and zonal contribution i.e. permeability-thickness, skin, oil and water influx from individual producing zones. In order to develop a full picture of how these two categories contribute to production performance, a detailed analysis should be conducted to understand their interaction.

Low permeability carbonates and chalk fields often require long multi-stage frac'ed horizontal wells which further complicates the analysis due to lack of measured data in each stage.

The Ekofisk filed development is a mature water flood, which includes both deviated and horizontal wells. Deviated wells are placed in the more crestal location, while the horizontal wells are generally placed towards the flanks where reservoir properties are of lower quality as compared to the field's crest. Production performance and optimization is largely dependent on efficient zonal stimulation, well and reservoir management. Understanding the distribution of fluid phases along the well, especially the water influx, may enable timely executed water shut-offs to mitigate water breakthrough. The traditional technique of understanding where and how much oil and water are being produced, require well intervention through production logging (PLTs). Well interventions are often difficult to execute due to limited access to platforms, the high cost of wells and production deferments. All of these factors limit efficient production optimization due to the inability to collect data in a timely manner for analysis. Furthermore, experiences from the Ekofisk field indicate that PLT data often gives inconclusive results due to known challenges of interpreting PLT data from horizontal wells.

An intervention free and cost efficient approach using inflow tracers has been piloted to acquire early time data, in addition to acquiring well and reservoir understanding throughout the well life. This approach was successfully developed and tested in a newly drilled horizontal Ekofisk field producer. The well was equipped with inflow tracers permanently installed in the completion string to identify individual zone's production contribution including the split by oil, gas and water. In addition, unique intra well tracers were injected into each zone during stimulation to gain knowledge of the stimulation efficiency. During well start up, clean out, transient and post transient production periods extensive sampling programs were executed. As a result, sufficient data has been acquired in order to complete reservoir characterization analysis together with traditional Pressure Transient Analysis (PTA), and then followed by production optimization.

The acquired tracer data and interpretation has been compared with conventional PLT interpretation to verify the former.

This is the first integrated application using permanently installed inflow tracers, injected intra well tracers and pressure data interpretation solution for reservoir characterization and production optimization performed.

The success of any improved oil recovery (IOR) project is largely dependent on how much oil is remaining to be mobilized within the targeted area of the partially depleted or mature reservoir. Partitioning tracers are generally used to measure residual oil saturation (Sor) or remaining oil saturation (ROS) in the near wellbore region via a single well chemical tracer test (SWCTT) or in an inter-well region via a partitioning inter-well tracer test (PITT). There is a limited repertoire of nonradioactive and environmentally friendly inter-well partitioning tracers for measuring ROS. A new class of environmentally friendly partitioning tracers was field tested, in a giant carbonate reservoir undergoing peripheral waterflood, for measuring ROS in inter-well regions in a depleted area.

The new partitioning tracers were qualified via laboratory experiments and are deemed to be very stable at reservoir conditions (213°F and a salinity range of 60-200 kppm). The field pilot was conducted concurrently with a set of non-partitioning inter-well chemical tracer test (IWCTT) to determine reservoir connectivity, water breakthrough times, and injector-to-producer pair communication in an area selected for an IOR/EOR field pilot. An elaborate sampling and analysis program was carried out over a period of 30 months.

This paper reviews the complete design and implementation of the test, operational issues, and the analyses and interpretation of the results. The breakthrough times of the passive and partitioning tracers are reported, and inter-well connectivity between the paired and cross-paired injectors and producers are analyzed. The ROS measured by a majority of the novel tracers is comparable to the saturations obtained via SWCTT, core and log derived saturations.

The combination of conventional IWCTT and the novel partitioning tracers via PITT has been very useful in analyzing well interconnectivity, understanding the reservoir dynamics and quantifying remaining oil saturation distribution in the reservoir. This has led to better reservoir description and an improved dynamic simulation model.

The In Salah CCS project in central Algeria is a world pioneering onshore CO₂ capture and storage project which has built up a wealth of experience highly relevant to CCS projects worldwide. Carbon dioxide from several gas fields is removed from the gas production stream in a central gas processing facility and then the CO₂ is compressed, transported and stored underground in the 1.9 km deep Carboniferous sandstone unit at the Krechba field.

Injection commenced in 2004 and since then over 3.8Mt of CO₂ has been stored in the subsurface. The storage performance has been monitored using a unique and diverse portfolio of geophysical and geochemical methods, including time-lapse seismic, micro-seismic, wellhead sampling using CO₂ gas tracers, down-hole logging and core analysis, surface gas monitoring, groundwater aquifer monitoring and satellite InSAR data. Routines and procedures for collecting and interpreting these data have been developed, and valuable insights into appropriate Monitoring, Modelling and Verification (MMV) approaches for CO₂ storage have been gained.

We summarize the key elements of the project life-cycle and identify the key lessons learned from this demonstration project that can be applied to other major CCS projects, notably:

• The need for detailed geological and geomechanical characterization of the reservoir and overburden;
• The importance of regular risk assessments based on the integration of multiple different datasets;
• The importance of flexibility in the design and operation of the capture, compression, and injection system.

The In Salah project thus provides an important case study for knowledge transfer to other major CCS projects in the planning and execution phases.

To obtain improved oil recovery (IOR), it is crucial to have a best-possible description of the reservoir and the reservoir dynamics. In addition to production data, information can be obtained from 4D seismic and from tracer monitoring. Interwell tracer testing (IWTT) has been established as a proven and efficient technology to obtain information on well-to-well communication, heterogeneities, and fluid dynamics. During such tests, chemical or radioactive tracers are used to label water or gas from specific wells. The tracers then are used to trace the fluids as they move through the reservoir together with the injection phase.

At first tracer breakthrough, IWTT yields immediate and unambiguous information on injector/producer communication. Nevertheless, IWTT is still underused in the petroleum industry, and data may not be used to their full capacity—most tracer data are used in a qualitative manner (Du and Guan 2005). To improve this situation, we combine tracer-data evaluation, 4D seismic, and available production data in an integrated process. The integration is demonstrated using data from the Snorre field in the North Sea. In addition to production data, extensive tracer data (dating back to 1993) and results from three seismic surveys acquired in 1983, 1997, and 2001 were considered.

Briefly this study shows that

• Seismic and tracer data applied in combination can reduce the uncertainties in interpretations of the drainage patterns.
• Waterfronts interpreted independently by tracer response and seismic dimming compare well.
• Seismic brightening interpreted as gas accumulation is supported by the gas-tracer responses.