Geochemical Techniques to Detect Sources of Fluids in Highly Pressured Casing-Casing Annuli CCA

The buildup of high casing-casing annulus (CCA) pressure compromises the well integrity and can lead to serious incidents if left untreated. Potential sources of water causing the elevated CCA pressure are either trapped water in the cement column or water from a constant feeding source. This study utilizes inorganic geochemical techniques to determine the provenance of CCA produced water as trigger for high pressure in newly drilled wells. Affinities in the hydrochemical (major, minor and trace elements) and stable isotopic (δ2H, δ18O) composition are monitored to identify single fluid types, multi-component mixing and secondary fluid alteration processes. As a proof-of-concept, geochemical fingerprints of CCA produced water from three wells were correlated with potential source candidates, i.e., utilized drilling fluids (mud filtrate, supply water) from the target well site, Early - Late Cretaceous aquifers and Late Jurassic - Late Triassic formation waters from adjacent wells and fields. Geochemical affinities of CCA water with groundwater from an Early Cretaceous aquifer postulate the presence one single horizon for active water inflow. Non-reactive elements (Na, Cl) and environmental isotopes (δ2H, δ18O) were found to be most suited tools for fluid identification. 2H/1H and 18O/16O ratios of supply water and mud filtrate are close to global meteoric water composition, whereas formation waters are enriched in 18O. Elevated SO4 and K concentrations and extreme alkaline conditions for CCA water indicates the occurrence of minor secondary alteration processes, such the contact of inflowing groundwater with cement or fluid mixing with minor portions of KCl additives. The presented technology in this study enables the detection of high CCA pressure and fluid leakages sources, thereby allowing workover engineers to plan for potential remedial actions prior to moving the rig to the affected well; hence significantly reducing operational costs. Appropriate remedial solutions can be prompted for safe well abandonment as well as to resume operation at the earliest time.

Lessons Learnt from a Successful Sampling While Drilling Campaign Delivering Formation Oil Samples and Saturation Pressure Measurements in High H2S Carbonates

As island development strategies gain focus for capitalizing deep offshore assets, limitations like fixed slot location bring about the need for drilling extended reach (ERD) wells with multiple drain holes and complex well geometry to maximize the reservoir coverage for increased production. Pressure testing and reservoir fluid sampling operations require long stationary time and pose a risk of differential sticking. Deploying a pressure testing and fluid sampling tool into the drilling bottom-hole assembly (BHA) helps in maintaining well control through continuous circulation and providing measures to retrieve the tool by rotation and jarring in case of pipe sticking. This paper presents the successful deployment of sampling while drilling tools in three ERD wells drilled using water based and oil based muds to acquire representative formation oil samples from a high H2S carbonate reservoir. The formation oil samples were collected immediately after drilling the well to the target depth for limiting the invasion to collect clean samples in shorter pump-out volume and time. After securing the samples, a phase separation test was performed by fluid expansion in a closed chamber to measure the saturation pressure of the oil. A 30-min long pressure build up was also performed for pressure transient analysis to estimate permeability. Formation fluid samples were collected, while pulling out the drilling BHA, within 12-48 hours of drilling the well by pumping out 100-170 liters of fluid from the formation in 4-6 hours. During clean up, absorbance spectroscopy identifies the fluid phases – gas, oil and water. Prominent trends observed in compressibility, mobility, sound slowness and refractive index measurements add confidence to the fluid identification and provide accurate contamination measurements. Single-phase tanks charged with nitrogen were used to assure quality samples for PVT analysis. The sample tanks are made of MP35N alloy and the flow lines are made of titanium that are both H2S resistant and non-scavenging materials and hence, a separate coat of non-scavenging material was not required. In highly deviated wells, sampling while drilling technology can close the gaps of the conventional wireline operation on pipe conveyed logging in addition to saving 5-days of rig time by eliminating the need for conditioning trips, a dedicated run for pressure testing and sampling and minimizing the risk of stuck pipe and well control incidents The results from downhole fluid analysis and PVT lab are compared in this paper. Going forward, this technology can eliminate the requirement of a pilot hole for pressure testing & sampling by enabling sampling in complex well geometries in landing sections and ERD wells. The paper concludes with discussions on suggested improvements in the tool design and capability and recommendations on best practices to align with the lessons learnt in this sampling while drilling campaign.

Integration of NMR Factor Analysis, Multifunction LWD Measurements, and T2 Modeling Improve Fluid Identification in Complex Carbonate Reservoirs

Carbonate environments are complex by nature and the characterization, based on their petrophysical properties, has always been challenging due to the pore heterogeneity. In this paper, we present the integration of factor analysis applied to while-drilling Nuclear Magnetic Resonance (NMR) data, full-suite data from a multifunction logging-while-drilling (LWD) tool, and modeling of the NMR T2 transverse relaxation time to improve the fluid typing interpretation in complex carbonate reservoirs. The interpretation results are essential for perforation and completion decisions in a high-angle development well. The carbonate reservoirs in this case study are within the Kujung formation in the East Java Basin. Kujung I is a massive carbonate reservoir with abundant secondary porosity, while Kujung II and III consist of interbedded thin carbonate reservoirs and shale layers. High uncertainty in identifying the fluid type existed in the Kujung II and III formations due to the presence of multiple fluids in the reservoir, the effect of low water salinity, as well as pore heterogeneity and diagenesis. Due to the high-angle well profile, LWD tool conveyance became the primary method for data acquisition. NMR while drilling and multifunction LWD tools were run on the same drilling bottomhole assembly (BHA) to provide complete formation evaluation and fluid identification. The NMR factor analysis technique was used to decompose the T2 distribution into its porofluid constituents. Thorough T2 peaks modeling was performed to interpret the fluid signatures from the factor analysis results. Borehole images, caliper, triple-combo, density-magnetic resonance gas corrected porosity (DMRP), as well as time-lapse data were evaluated to identify the presence of secondary porosity and narrow down the T2 fluid signatures interpretation. Each of the porofluid signatures were identified and validated in the Kujung I formation with its proven gas and thick water zone. These signatures were then used as references to interpret the fluid types in the Kujung II and III formations. Gas was identified by a low-amplitude peak in the shorter T2 range between 400 ms to 1 s. Oil or synthetic oil-based mud (SOBM) filtrate was indicated by a high-amplitude peak in the longer T2 range (>1.5 s). The water signatures are very much dependent on the underlying pore sizes. Larger pore sizes will generate longer T2 values, which could fall into the same T2 range as hydrocarbon. For that reason, it is important to combine the NMR porofluid signatures interpretation with other LWD data to restrict the fluid type possibilities. This integrated methodology has successfully improved the fluid type interpretation in the Kujung II and III thin carbonate reservoir targets and was confirmed by the actual production results from the same well. This case study presents excellent integration of LWD NMR with other LWD data to reduce fluid type uncertainties in complex carbonate reservoirs, which were unresolved by conventional interpretation methods. Based on this success, a similar integrated NMR factor analysis method can be applied to future development wells in the same field.

Bringing the Best of Sampling While Drilling in Highly Deviated S-Profile Wells: Case Studies from a Brown Field, Sabah, Offshore Malaysia

Sampling While Drilling has undergone significant changes since its advent early this decade. The continuum of applications has primarily been due to the ability to access highly deviated wellbores, to collect PVT quality and volume of formation fluids. The increased confidence is also a result of numerous applications with varied time-on-wall without ever being stuck. This paper demonstrates the contribution of this technology for reservoir fluid mapping that proved critical to update the resource assessment in a brown field through three infill wells that were a step-out to drill unpenetrated blocks and confirm their isolation from the main block of the field. As a part of the delineation plan, the objective was to confirm the current pressure regime and reservoir fluid type when drilling the S-profile appraisal wells with 75 degrees inclination. Certain sand layers were prone to sanding as evidenced from the field's long production history. Due to the proven record of this technology in such challenges, locally and globally, pipe-conveyed wireline was ruled out. During pre-job planning, there were concerns about sanding, plugging and time-on-wall and stuck tools. Empirical modeling was performed to provide realistic estimates to secure representative fluid samples. The large surface area pad was selected, due to its suitability in highly permeable yet unconsolidated formations. For the first well operation, the cleanup for confirming formation oil began with a cautious approach considering possible sanding. An insurance sample was collected after three hours. For the next target, drawing on the results of the first sampling, the pump rate was increased early in time, and a sample was collected in half the time. Similar steps were followed for the remaining two wells, where water samples were collected. Oil, water, and gas gradients were calculated. Lessons learnt and inputs from Geomechanics were used in aligning the probe face and reference to the critical drawdown pressure (CDP). A total of 4,821 feet (1,469 meters) was drilled. 58 pressures were acquired, with six formation fluid samples and five cleanup cycles for fluid identification purpose. The pad seal efficiency was 95%. The data provided useful insights into the current pressure regime and fault connectivity, enabling timely decisions for well completion. The sampling while drilling deployment was successful in the highly deviated S-profile wells and unconsolidated sand, with no nonproductive time. Because of the continuous circulation, no event of pipe sticking occurred, thereby increasing the confidence, especially in the drilling teams. The sampling while drilling operations were subsequent, due to batch drilling, with minimal time in between the jobs for turning the tools around. The technology used the latest generation sensors, algorithms, computations and was a first in Malaysia. The campaign re-instituted the clear value of information in the given environment and saving cost.

Successful Reservoir Fluid Characterization and Testing While Overcoming the Challenges of Falling Oil Price and a Pandemic: A First for an Integrated Brown Field Alliance Project in Sarawak, Malaysia

A brown field, offshore Sarawak, Malaysia, with multiple sub-layered laminated sands of varied pressure regimes and mobility ranges, was challenged by depletion, low mobility and uncertainty in the current fluid types and contacts. Optimal dynamic fluid characterization and testing techniques comprising both Wireline and Logging While Drilling (LWD) were applied in nine development wells to acquire reliable formation pressure data and collect representative fluid samples including fluid scanning. Some of the latest technologies were deployed during the dual crises of falling oil price and the Covid-19 pandemic. The S-profile wells were drilled using oil-base mud (OBM) with an average deviation of 60 degrees. Formation Pressure While Drilling (FPWD), Fluid Sampling While Drilling (FSWD) and wireline formation testing, and sampling were all utilized allowing appropriate assessment of zones of interest. Various probe types such as Conventional Circular, Reinforced Circular, Elongated, Extra-Elongated and Extended Range Focused were used successfully, ensuring that the right technology was deployed for the right job. Formation pressure and fluid samples were secured in a timely manner to minimize reservoir damage and optimize rig time without jeopardizing the data quality. As a classified crisis due to the pandemic, rather than delaying the operations, a Remote Operations Monitoring and Control Center was set-up in town to aid the limited crew at rig site. A high success rate was achieved in acquiring the latest formation pressure regimes, fluid gradients, scanning and sampling, allowing the best completion strategy to be implemented. With the selection of the appropriate probe type at individual sands, 336 pressure tests were conducted, 44 fluid gradients were established, 27 fluid identification (fluid-id / scanning) pump-outs were performed, and 20 representative formation fluid samples (oil, gas, water) were collected. Amongst the Layer-III, Layer-II and Layer-I sands, Layer-I was tight, with mobility < 1.0 mD/cP. Wireline focused probe sampling provided clean oil samples with 1.4 to-3.7 wt. % OBM filtrate contamination. The water samples collected from Layer-II during FSWD proved to be formation water and not injection water. The wells were thus completed as oil producers. Reliable fluid typing and PVT quality sampling at discrete depths saved rig time and eliminated the requirement of additional runs or services including Drill Stem Testing (DST). This case study has many firsts. It is the first time where latest fluid characterization and testing technologies in both Wireline and LWD were deployed for an alliance project in Malaysia and that too during dual crises of falling oil price and the pandemic aftermath. Overcoming various challenges including limited rig site manpower, there was no delay in completing the highly deviated wells with tight formations in a single drilling campaign and provided rig time savings. For the purpose of this case study, two wells have been discussed. First well used the wireline focused sampling technology and the second used the FSWD technology.

Using the Modified Resistivity–Porosity Cross Plot Method to Identify Formation Fluid Types in Tight Sandstone with Variable Water Salinity

It is generally difficult to identify fluid types in low-porosity and low-permeability reservoirs, and the Chang 8 Member in the Ordos Basin is a typical example. In the Chang 8 Member of Yanchang Formation in the Zhenyuan area of Ordos Basin, affected by lithology and physical properties, the resistivity of the oil layer and water layer are close, which brings great difficulties to fluid type identification. In this paper, we first analyzed the geological and petrophysical characteristics of the study area, and found that high clay content is one of the reasons for the low-resistivity oil pay layer. Then, the formation water types and characteristics of formation water salinity were studied. The water type was mainly CaCl2, and formation water salinity had a great difference in the study area ranging from 7510 ppm to 72,590 ppm, which is the main cause of the low-resistivity oil pay layer. According to the reservoir fluid logging response characteristics, the water saturation boundary of the oil layer, oil–water layer and water layer were determined to be 30%, 65% and 80%, respectively. We modified the traditional resistivity–porosity cross plot method based on Archie’s equations, and established three basic plates with variable formation water salinity, respectively. The above method was used to identify the fluid types of the reservoirs, and the application results indicate that the modified method agrees well with the perforation test data, which can effectively improve the accuracy of fluid identification. The accuracy of the plate is 88.1%. The findings of this study can help for a better understanding of fluid identification and formation evaluation.

Characterizing Downhole Fluid Analysis Sensors As Digital Twins: Lessons of the Machine Learning Approach, The Physics Approach and the Integrated Hybrid Approach

Digital fluid sampling is a technique utilizing downhole sensors to measure formation fluid properties without collecting a physical sample. Unfortunately, sensors are prone to drift over time due to the harsh downhole environmental conditions. Therefore, constant sensor evaluation and calibration is required to ensure the quality of analysis. A new technique utilizes a virtual sensor as a digital twin which provides a calibration that can be utilized by the physical twin. Digital twin technology enables the end-user to operate and collaborate remotely, rapidly simulate different scenarios, and provide improved accuracy via enhanced up-to-date calibrations. With respect to downhole fluid identification, the contribution of harsh environmental conditions and sensor drift can also be mitigated by realizing a virtual implementation of the fluid behavior and the individual sensor components. Historically, the virtual behavior of a digital twin has been constructed by a combination of complex multi-physics and empirical modeling. More recently, access to large datasets and historical results has enabled the use of machine learning neural networks to successfully create digital twin sensors. In this paper, we explore the efficacy of constructing a digital twin on a single downhole optical fluid identification sensor using both the machine learning nonlinear neural network and the complex, multi-physics' based modeling approaches. Advantages and lessons to be learned from each individual method will be discussed in detail. In doing so, we have found a hybrid approach to be most effective in constraining the problem and preventing over-fitting while also yielding a more accurate calibration. In addition, the new hybrid digital twin evaluation and calibration method is extended to encompass an entire fleet of similar downhole sensors simultaneously. The introduction of digital twin technology is not new to the petroleum industry. Yet there is significant room for improvement in order to identify how the technology can be implemented best in order to decrease costs and improve reliability. This paper looks at two separate methods that scientists and engineers employ to enable digital twin technology and ultimately identify that a hybrid approach between machine learning and empirical physics'-based modeling prevails.

Fluid Identification Derived from Non-Electric Measurements and Reservoir Characterization of Tight Carbonate in Sichuan Basin, China

Natural gas production in the Sichuan Basin reached 30 billion m3 in 2020, but the gap between this and the production goal of 50 billion m3 in 2025 requires further exploration. The complex mineralogy and low porosity in tight carbonate reservoirs lower the accuracy of formation water saturation calculation from Archie's equation, which brings uncertainties to the reservoir characterization. It is, therefore, necessary to incorporate other methods as supplements to methods based on resistivities. This paper outlines a method that incorporates wireline induced gamma spectroscopy, nuclear magnetic resonance (NMR), array dielectric, and borehole images. Spectroscopy is not only utilized to estimate the mineralogy of the reservoir, but it also provides non-electric measurements, such as chlorine concentration and thermal neutron capture cross-section (sigma). The amount of chlorine in the formation is proportional to the water volume in the reservoir, thus formation water saturation. Sigma is also an indicator of the formation water saturation. It enables formation water saturation calculation without resistivities. Case studies are presented from carbonate reservoirs in the Sichuan Basin, China. A robust and comprehensive petrophysical description of mineralogy, porosity, pore geometry, free fluid volume, rock type, and formation water saturation is presented. Calculation of formation water saturation from chlorine and sigma proves to be successful in both water-based mud and oil-based mud environments. The depth of investigation (DOI) of chlorine from spectroscopy is about 8 to 10 in. for 90% of the signal. The various DOI of different measurements must be considered when performing the fluid identification. Bound fluid saturation could reach more than 50% in tight carbonate reservoirs. Formation water saturation is not the only factor that determines the fluid type. Free fluid saturation from NMR must be incorporated. Finally, a robust methodology integrating formation water saturation derived from dielectric and spectroscopy, and free fluid saturation derived from NMR shows great advantage in fluid identification in tight carbonate reservoirs. This paper discusses a novel combination of wireline logging tools for the fluid identification of tight carbonate reservoir in Sichuan Basin. It lowers the uncertainty in the estimation of formation water saturation when application of resistivities is limited in oil-based mud environments. The gas zones identified by the new method have promising gas productions. The workflow can also be applied to other tight carbonate plays in China.