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Abstract During the 2014 SPWLA Topical Meeting on “Educating the Petrophysicist”, it recommended that “A minimum set of standards in terms of both knowledge and skills (competencies) for an entry level petrophysicist (SPWLA, 2014). Similar proposal has been raised before as well (Loermans, 2002). With the rapid advance in technology, continuous crew change, and a natural pandemic affecting the oil and gas industry, the learning pattern has been changing from traditional in-person structured courses to more online, on-demand, short course training. For those interested in entering petrophysics discipline or furthering their petrophysics knowledge and skills, the learning path is less clear than other discipline like reservoir engineering, or geology, due to the lack of university degree program in Petrophysics. SPWLA Education SIG has taken on this challenge and developed skill set guidelines for petrophysicists as independent contributors. The current version of the guidelines covers topics including: General Geoscience and Engineering Operations, Fundamental Petrophysical Data Acquisition, Integrated Formation Evaluation, LWD Petrophysics in Formation Evaluation and Geosteering, Reservoir Dynamic Surveillance, Integrated Petrophysical Modeling, and Data Driven Petrophysics. In each topic, it includes basic skills as well as specialized skills. The document was developed with oil and gas industry in mind and can be adapted for petrophysicists working in related fields such as geothermal, mining, carbon management, water resources evaluation, etc. The document will be useful for students interested in learning to be a petrophysicist, a company interested in developing a training program for petrophysicists, and an organization interested in developing skill assessment program for petrophysicists.
Chao, Du (CNOOC) | Costam, Ronald Yusef (CPOC) | Xiannan, Wang (CNOOC) | Fadjarijanto, Ari (CPOC) | Daungkaew, Saifon (Schlumberger) | Gao, Bei (Schlumberger) | Duangprasert, Tanabordee (Schlumberger) | Edmundson, Simon (Schlumberger) | Perrin, Cedric (Schlumberger) | Lopes, Jose Luis (Schlumberger) | Airey, Peter (Schlumberger) | Andic, Hikmet (Schlumberger) | Hoong, Tan Yinn (Schlumberger) | Ramli, Mohd Razman (Schlumberger) | Khunaworawet, Tanawut (Schlumberger) | Watana, Kulapat (Schlumberger) | Phanatamporn, Kitithorn (Schlumberger)
ABSTRACT As oil and gas exploration and production extends to deeper buried reservoirs, challenges such as lower porosities and Ultra High Temperature have been encountered. Several reservoirs in the Asian region, the North Malay basins in the joint development area between Thailand and Malaysia, and the Baiyun Sag and Qiong Dongnan basin in offshore China are considered to have the highest known temperature gradients due to their geological depositional system and hydrocarbon charging mechanism. More than fifty percent of wells drilled in these areas have temperatures close to/or higher than 170 degC, and some reach above 200 degC. In number a of projects in these areas, the logging requires tools that can withstand up to 230 degC. Traditionally, Wireline Formation Testers (FT) with fixed rate and volume pre-test and old sampling technique using a dumping chamber (i.e. without pumping capability) had been the standard formation tester when temperatures reached 400degF (204 degC) and higher. The tools were not flasked and therefore, the temperature transient affected the quality and accuracy of pressure data. Also, in such harsh environment, it is very difficult and time consuming to go back to a good mobility station for sampling after a pressure measurement, due to reservoir heterogeneity and depth error. This paper discusses a project for a new slim hole ultrahigh temperature Wireline Formation Tester designed to obtain both pressure profiles and perform downhole Pressure Volume Temperature (PVT) fluid sampling with pump-out capability and downhole fluid sensors such as viscosity, density and resistivity in extreme HT environments. In addition, this slim hole ultrahigh temperature tool dimension has more clearance between the tool and formation, and therefore, less chance of having this tool get stuck during slim hole logging. The tool was first deployed in the North Malay Basin and since early 2018, five development wells were logged where a total of 76 pre-tests, four pump-out and ten fluid sampling stations were conducted. The main objectives for this FT tool were to obtain formation pressure, identify reservoir fluid and quantitative CO2 measurements zone by zone. The results will be discussed operationally and technically, in terms of data quality and accuracy and compared with on-site surface analysis. In addition, this tool improves significantly operationally compared to the previous tools and with some operators having mixed perceptions on running Wireline FT tool with bigger ODs, especially drilling departments. Having this new slim hole tool with its smaller OD increases their confidence level in running it. For Deepwater Offshore China, an operator has been facing challenges to explore a brand-new block such as pore pressure distributions profile, reservoir quality, and constrained logging period. The main objectives for the extreme FT are to obtain the formation pressure for drilling purpose, to understand reservoir potential to optimize the perforation interval for Drill Stem Test, and to narrow logging operation time window due to seasonal weather. This new ultra-high slim hole was therefore proposed to log in this challenging environment. This field example shows a significantly improved pre-test and sampling capability in the lower mobility ranges, which some previous generations of formation testers had struggled with in the past, in one run and without sacrificing testing efficiency. The effective time for valid pretest can be achieved even in the range of mobility 0.01 mD/cp, high pressure of >11000 psi, and high temperature of >180 degC. This paper discusses pre-job planning and actual job execution results in both locations. The challenges of logging and lesson learned are addressed. This is the first attempt in evaluating reservoirs in the deeper and HT sections to properly understand reservoir fluids.
Abstract The necessity of knowing formation pressure is crucial to classifying pressure regimes for better understanding in well planning and to de-risk potential abnormal pressure conditions before any future field development wells are drilled, consequently minimizing operational cost. Wireline formation pressure testing has been a useful and reliable technology, that has evolved to confront the challenge of ultra-low permeable reservoir conditions by innovating and improving pump capability, accuracy in pressure measurements, automated control and the implantation of Formation Rate Analysis (FRA) intertwined with an Artificial Intelligent tool. In any pressure testing, the key factor is to be able to withdraw volume from the formation to generate a disturbance on formation pore pressure that a pressure gauge can measure. In the past this has been a difficult task in ultra-low permeable zones. The new generation of wireline tools are capable of withdrawing volume from ultra-low permeable reservoirs, with mobilities lower than 0.01mD/cP. This has been made possible by utilizing control of the pump speed down to 0.0003cc/s which then gives the operator the ability to test ultra-tight formations without the need for inflatable packers. By pulling down the pressure at an extremely low rate and using Artificial Intelligence to control the rate by knowing the formation rate, a proportional amount of volume can be extracted without calling it a tight test. During the operation by observing the rate, and making sure the pump is not oscillating, which indicates the formation rate is lower than the lowest rate the pump can withdraw, the test can be validated for formation flow and the pressure transient of the build – up can be analysed to confirm that at least spherical flow is observed. Once reservoir communication has been confirmed and by analysing drawdown and build-up pressure versus volume withdrawn and implementing the FRA equation, the reservoir pressure can be back calculated by considering isothermal compressibility and FRA slope. This paper highlights the best technical approach to quality check and quality control these tests, showing examples of various wells, where the technique has been used to predict a formation pressure, which can be used for further use for field development, drilling optimisation and production profiles. These pressures would never have been possible using static rates and volume.
Abstract The Alta field in the Barents Sea was discovered in 2014. The reservoir formation is primarily carbonate rocks with high formation water salinity. Extensive waterflooding processes have led to an approximately 200-m rise of water level. The complexities and uncertainties regarding imbibition, current free water level, and pseudo fluid contacts within the field translate into uncertainty in the hydrocarbon volume estimation. Initial, triple-combo-based petrophysical evaluations have already been updated using advanced log measurements, as reported in an earlier publication. The evaluation is now consolidated by using two new techniques relying on advanced spectroscopy logging and combination with dielectric dispersion logging. Their objective is to further reduce the uncertainty in water saturation associated with variable apparent water salinity. The present contribution proposes a workflow that relies on two novel techniques. The first technique is a direct quantitative measurement of formation chlorine concentration from nuclear spectroscopy, which helps resolve the formation's apparent water salinity and provides a way to calibrate formation matrix sigma. The second technique relies on the existing combined inversion of dielectric dispersion and formation sigma, including explicitly invasion effects. This second technique benefits from the first technique's insight to adjust sigma interpretation and provide bounds for possible salinity variations. The workflow provides robust flushed and unflushed zone salinities, here the most uncertain and variable parameter, combined with accurate estimations of virgin and residual hydrocarbon saturations. The quantification of dielectric textural parameters describing how the water is shaped inside the formation is also improved, contributing to the improvement of virgin zone hydrocarbon saturation estimation.
Partouche, Ashers (Schlumberger) | Yang, Bo (Schlumberger) | Tao, Chen (Schlumberger) | Sawaf, Tamim (Schlumberger) | Xu, Lina (Schlumberger) | Nelson, Keith (Schlumberger) | Chen, Hua (Schlumberger) | Dindial, Deo (Schlumberger) | Edmundson, Simon (Schlumberger) | Pfeiffer, Thomas (Consultant)
ABSTRACT Wireline formation testing has evolved from discrete pressure measurements, introduced in the 1950s to measuring pressure gradients and fluid contacts since the 1970s. Technology introduced in the late 1980s and onwards added interval pressure transient testing, focused sampling, and downhole fluid analysis. Thirty years later, this paper shows data examples of a recently developed formation testing platform in a wide range of environments, and applications, that change how we plan, acquire, and use formation testing. The dual-flow-line architecture of the formation testing platform is designed to systematically address shortcomings of legacy technology, enabling focused sampling in the tightest conventional formations, as well as transient testing in high mobility environments. Specialized pre-job planning software evaluates conveyance options to minimize friction and borehole contact, estimates the available flow rate, compares cleanup performance of the different inlets, and simulates transient testing responses. During the operation, the platform uses hardware embedded automation algorithms that execute routine tasks in a consistent and highly efficient manner, leaving more time for the user to focus on data quality and value of the measurements. Case studies from Mexico, Norway, and the US demonstrate specific improvements in capability and performance. Field data from Mexico shows focused sampling of gas condensate from a heterogeneous submillidarcy carbonate formation in an HP/HT well drilled with oil-based mud. Controlled downhole decompression of crude oil in the flowline at a sampling station in Norway enabled real-time measurement of its bubble point pressure to within 6 psi of that measured in the laboratory. Another case study integrates accurate relative asphaltene gradients into an existing reservoir fluid study to prove reservoir connectivity across a large lateral distance in a producing field. Application of the dual packer subsystem demonstrates inflation within four minutes and pure oil samples within 90 minutes on station in a 1.5-md/cp fractured basement formation. The fine pump control at a low rate enabled sampling just below reservoir pressure in Alaska and a case from the Gulf of Mexico demonstrates the real-time impact of fluid properties on the understanding of reservoir architecture and completion design. The presented examples highlight the impact of downhole automation, define the new operating envelope for formation testing in the most challenging environments, and highlight how the technology development leads to decision making on a broad reservoir scale by providing contextual answers rather than an accumulation of facts and figures.