Loss of barrier assurance and primary containment occurrences whether downhole or at surface have impacted safe well operation and production funnel significantly. Complex well head design, inadequate cement behind casing, threat of shallow gas presence and multiple downhole tubulars leaks are some of the common perils in sustaining the production. Apart from frequent pressure monitoring, risk assessment and mitigation plans to tackle the issues head-on, a new fresh perspective is required to manage well integrity and diagnostic holistically. This paper will highlight application of geochemical method as the new eye to trace source of well integrity issues and emulates forensic engineering to investigate well barrier failures.
Crude and gas compositional analysis from C1 up till C36 carbon chain plays a key role in determining the possible scenarios of leak paths and type of fluid expelled from the wellbore. The best forensic analysis could be produced utilizing multiple samples which represent different stages of well life starting from open-hole exploration drilling, development, production and towards the well abandonment stage. Comparing samples composition at each stage with reference to the baseline while evaluating the existing or newly acquired cement bond and diagnostic logs will help to complete the lingering puzzle.
Results showed that the origin of the fluid samples expelled from the wellbore are successfully traced in a much more economical way with faster turn-around time compared to the conventional diagnostic method. It helps to point out the most likely well integrity elemental failure which has triggered immediate actions to revive the production. Plan to feed in the cash flow has been accelerated 6 months ahead through work-over activities and number of unhealthy well strings has been reduced by 12%. Production deferment is also reduced by half million ringgit equivalent value.
In a nutshell, the case studies provide an eye-opening insight towards predictive and quantitative well integrity solutions to support production. Forward looking the geochemical forensic method can be further tailored for strategic well diagnostic solutions as more data comes in. Time to action could be further reduced with the introduction of advanced on-site analysis technology to boost the restoration efforts.
Geochemistry plays a key role in oil and gas business and often, it has the reputation of providing the most economical way to establish the ground truth for any analytical work done to trace hydrocarbon presence. Conventional ways in determining hydrocarbon fluid type and flow potential such as wireline formation tester, optical fluid analyzer, well testing, downhole and surface fluid samples could be an advantage or a headache if delineation of hydrocarbon presence is masked by high contamination from drilling fluid or non-representative samples. Often whenever any sudden major production hiccups occur, many factors come in which may cloud the real root cause identification. Hence, geochemistry method offers a unique solution in tracing the hydrocarbon presence and also the possible sources where it originates from. Methodology and principles of gas-chromatograph (GC) fingerprinting, case studies for application and value creation to the business are the scopes of this paper.
Examining the DNA and composition unique to each hydrocarbon fluid sample in the lab can be an intriguing process which requires shorter time compared to conventional analytical work. Requiring only few drops of hydrocarbon fluid, synthetic-based mud and base oil samples as input into the GC spectrometer machine, the unique chromatogram signature from each fluid will be overlaid onto each other for comparison and quantification of contamination level.
The case studies presented in this paper will highlight the key characteristics of live hydrocarbon signature as compared to the dead oil or drilling fluid signature which acts as the outlier or contaminant to the samples. Values created in terms of proving the hydrocarbon discovery, refining well testing decision based on the fingerprinting results which involves stakeholder's interest, determination of potential well barrier leaks, optimizing well stimulation design and possible sources of hydrocarbon migration into the wellbore will also be highlighted.
In a nutshell, application of GC fingerprinting to ascertain hydrocarbon fluid type is successfully proven, cost effective and technically viable approach. Recognizing the DNA and unique signature of each fluid will be an added advantage for short term and long term business investment strategies.
Zulkipli, Siti Najmi Farhan (PETRONAS Carigali Sdn. Bhd.) | Mehmet Altunbay, Michael (PETRONAS Carigali Sdn. Bhd.) | Gaafar, Gamal Ragab (PETRONAS Carigali Sdn. Bhd.) | Shah, Jamari M. (PETRONAS Carigali Sdn. Bhd.)
Objectives of obtaining in-situ values of water saturation, formation water salinity, true formation resistivity (Rt) and SCAL data by core analysis can only be achieved if extraneous fluid invasion is kept at a controlled level and corrected for it or be prevented. The impossibility of zero invasion of cores by mud-filtrate makes the traced-coring a compelling method. Application of liquid based tracers such as tritium and deuterium oxide (D20) to determine the amount of fluid invasion is highly recommended in the event of critical in-situ formation properties need to be determined from core. This study presents a set of key factors for controlling invasion of core by extraneous fluids, best practices in quantifying the fluid invasion, handling core at the surface, and suggests types of analyses, specifically, for unconsolidated formations. A comparison of petrophysical parameters determined from traced-core against the results of LWD log interpretation of the same interval is also presented to assess the success/failure of the recommended practices.
The main use of core-driven parameters has dual functionalities. They are used for calibrating LWD data and also are used to form a statistical database for static modeling. Calibration of LWD data with properly obtained core parameters could minimize uncertainties in calculated petrophysical parameters and establish a ground-truth in petrophysical work especially in water saturation (Sw) calculations. In our case study, good agreements are observed between log derived and core measured water saturations and salinity values extracted from the core against salinity from petrophysical study.
Proper time management, core preservation technique, prompt logistical arrangements and well-site core plugging are seen as the main driving factors for a successful coring job. Comparison of fluid invasion profiles between core plugs drilled at well-site and plugs drilled later in the lab are presented to demonstrate and emphasize the importance of time-factor which constitutes the main challenge in the case study and in general. The lack of data from uncontaminated core may result in significant financial losses that may manifest itself as bypassed productive zones, erroneously determined as wet or no-production (dry) intervals, wrong completions or incorrect quantification of actual and recoverable hydrocarbons. Some of these problems are associated with lack or mismanagement of uncertainties in calculation procedures/algorithms; therefore, can be alleviated or lessened with representative and accurate core data. In addition, analyses results based on the representative core could promote better understanding of reservoir behavior and catalyze more refined reservoir management strategy.
The experience acquired in this study revealed and ranked the importance of timing of the events and the procedural steps to obtain minimally invaded core plugs in a traced-core operation. Time is the most critical factor to prevent post-drill fluid-invasion and fluid re-distribution within a core which adversely impact core analysis results. Therefore, the optimum time allowed between the coring and laboratory tests, core transportation strategy, corresponding contamination of core as a function of time, recommended tests, selection of tracers and quick calculation of required tracer volume are the outputs that are elaborated in this paper. This study also highlights potential challenges in coring unconsolidated formations and serves a mitigation plan for lessening invasion of core by providing a set of recommendations for best practices.
Haddad, Sammy S (Schlumberger) | Zulkipli, Siti Najmi Farhan (PETRONAS Carigali Sdn Bhd) | Sinnappu, Suresh (Schlumberger) | Johan, Zailily Johfizah (Schlumberger) | Kyi, Ko Ko (Petronas Carigali Sdn Bhd) | Wa, Wee Wei (Schlumberger) | Tan, Willy (Schlumberger)
Proving a hydrocarbon bearing zone has a significant impact on appraising a well. Pressure gradient and fluid sampling are typically used to identify fluid type in exploration phase. In addition, to confirm if the field is viable for oil & gas production, there is a need to ascertain volume of hydrocarbon from petrophysical evaluation. Aside from this evaluation, reference to adjacent development wells occasionally become common for the operator to aid in reservoir study and plan for development.
This work is based on a case study on a Sarawak Basin field, drilled with Water Base Mud, which has three reservoirs of interests stretching across Clastics and Central Luconia Carbonate on the bottom zone. The poor quality sand and tight upper zone are challenging for reservoir evaluation. This has called for the application of multi-frequency dielectric tool for fluid saturation and advanced downhole fluid analyzer to obtain PVT equivalent fluid analysis in real time.
With the dielectric tool showing the presence of hydrocarbon in both clastic and carbonate formations, downhole fluid analysis was planned to verify the mobile formation fluid and successfully guided the identification of oil and water in clastic formation and gas in the carbonate reservoir. The presence of water in clastic formation was not expected since the water producing interval is located at about 100 m down dip from a nearby development well that is producing gas. Dispute in results, in addition to tight nature of the reservoir has triggered the need for larger scale testing. A DST was initially planned by the operator after the well has been cased. With cost and time consideration, the decision was changed to run the formation tester dual packer module to perform interval pressure transient testing (IPTT). This paper will present the results of IPTT, fluid analysis and dielectric tool to demonstrate the methodology used in this case study field evaluation.