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.
Jamaludin, Izzuddin (PETRONAS Carigali Sdn Bhd) | Mandal, Dipak (PETRONAS Carigali Sdn Bhd) | Arsanti, Dian (PETRONAS Carigali Sdn Bhd) | Dzulkifli, Izyan Nadirah (PETRONAS Carigali Sdn Bhd) | Zakaria, Nurul Azami (PETRONAS Carigali Sdn Bhd) | Mohamad Salleh, Salhizan (PETRONAS Carigali Sdn Bhd) | Ahmad Hawari, Saiful Adli (PETRONAS Carigali Sdn Bhd) | Mohd Azkah, Mohd Zubair (PETRONAS Carigali Sdn Bhd)
Data acquisition remains one of the crucial activities to be consistently executed throughout field life for any oilfield development. Significant operating expenditure (OPEX) is allocated each year to understand reservoir performance, thus reduce uncertainties and enable optimizations. This paper aims to highlight the issues faced during simulation model history matching (HM) process of a waterflood reservoir, including understanding of depositional environment and production data integrity. The output is utilized to improve recovery factor (RF) via infill opportunities and water injection optimization.
Field A has run a second shot of 3D seismic in 2006 (first in 1995) and processed into a time lapse, 4D seismic. In 2014, a cased hole logging campaign utilizing the high precision temperature, spectral noise logging (HPT-SNL) tool has been completed to check the integrity and flow contribution of 12 wells in Reservoir-X. Within the same period, a pulse pressure testing (PPT) was carried out to verify the communication between wells, in addition to acquiring regular surveillance data which helped to improve reservoir simulation study.
The 4D seismic helped to understand the areal waterflood front movement and explained the water cut trend anomaly in an updip well which experienced earlier water breakthrough than near downdip producers. Moreover, it helped to identify a bypass oil zone which can potentially be an infill location. As most of the wells are on dual string completion, the HPT-SNL campaign helped to improve production allocation of multi stacked reservoirs as well as identify problematic wells which required rectification jobs. The PPT assisted in identifying a baffle zone to explain the poor pressure support observed in some producers in the south from the nearby water injectors. All data interpretations were incorporated into final HM model which subsequently identified infill locations and the reservoir management plan (RMP) was successfully revised. An infill program was executed in 2015, which successfully secured additional EUR of ~9 MMstb. Based on the studies and outcome of the infill campaign water injection optimization helped to improve production and added ~2 MMstb reserves, through voidage replacement ratio (VRR) optimization and oil producer (OP) to water injector (WI) conversion. With these efforts, team could successfully project RF of >55%.
This case study demonstrates how acquiring focused surveillance data and their effective integration in performance analysis in simulation study helps to reduce uncertainties, unveils infill opportunities, improves production injection optimization and thus helps to improve the recovery factor in brown fields.
Riyanto, Latief (PETRONAS Carigali Sdn Bhd) | Sidek, Sulaiman (PETRONAS Carigali Sdn Bhd) | Hugonet, Vincent (PETRONAS Carigali Sdn Bhd) | Yusuf, M Hafizi (PETRONAS Carigali Sdn Bhd) | Salleh, Nurfarah Izwana (PETRONAS Carigali Sdn Bhd) | Ambrose, Jonathan Luke (SMS Oilfield)
Many oil and gas fields have long been suffering from sand production due to either the absence or failure of primary well sand control. To avoid mobilizing costly work-over rig to pull out the tubing, operators have tried various thru-tubing remedial sand control. The well's condition such as sands accumulation and space constraints due to small inner diameter of tubing always make this remedial job challenging. It is not surprising that the results are not all satisfactory.
Among the industry-recognized remedial sand control, Stand Alone Screen (SAS) is the simplest and the cheapest method. Many SAS have been installed but most were failed with screen erosion as the main failure mechanism. Flowing high velocity fluid with sands wears out the screen fast making it impossible for the sands to bridge and to create formation sand pack around the screen.
Ceramic Sand Screen (CSS) technology which was recently introduced to the industry aims to address this erosion issue. Having more than ten times hardness of stainless steel, sintered silicon carbide ceramic material in CSS offers superior resistance to wear. The pilot was conducted by installing CSS in three (3) selected wells with sand production history. While waiting for acoustic sand monitoring installation, the wells were put on production with the same choke size and regular manual samplings were conducted to monitor the sand production.
The acoustic sand monitoring campaign began in November 2017. Sands production was carefully monitored during the process to determine the final choke size at which the wells would continuously produce. In the middle of the campaign due to adverse weather conditions, all non-essential personnel had to be abruptly demobilised from the field leaving acoustic sensors hooked-up to the respective flow line. This gave opportunity to have unplanned extended sand monitoring window.
Loss of Primary Containment (LOPCs) occurred in two CSS wells not long after that. In one the choke body was heavily eroded and the other well had a punched hole at the first elbow of the flowline. These incidents prompted full investigation to be conducted. This included pulling out the installed CSS and performed tear down analysis. Acoustic sand monitoring that just happened to be available in one of the wells proved to be critical in understanding the CSS failure.
The paper presents briefly on the CSS pilot project, the chronology of events until the incident, sands production trend from the acoustic sand monitoring. Using all available information, the paper provides details analysis on CSS failure mechanism.
Rozlan, M Rizwan (PETRONAS Carigali Sdn Bhd) | Che Hamat, W Afiq Farhan (PETRONAS Carigali Sdn Bhd) | Ishak, M Faizatulizuddin (PETRONAS Carigali Sdn Bhd) | Chin, Jennie (Schlumberger) | Gil, Joel (Schlumberger) | Tan, Chun Khai (Schlumberger) | Arsat, Maisara (Schlumberger) | Elshourbagi, Saeid (PETRONAS Carigali Sdn Bhd) | Syed Abd Rahim, Sy Puteh Mariah (PETRONAS Carigali Sdn Bhd) | Abg Ahmad, Khairunnisa (PETRONAS Carigali Sdn Bhd) | Ismail, A Luttphi (PETRONAS Carigali Sdn Bhd) | Nguyen, Truong Son (PETRONAS Carigali Sdn Bhd) | Ahmad Pauzi, A Faris (PETRONAS Carigali Sdn Bhd) | Md A Jabar, M Zawawi (PETRONAS Carigali Sdn Bhd) | A Satar, Afzan (PETRONAS Carigali Sdn Bhd) | Misron, M Al Perdaus (PETRONAS Carigali Sdn Bhd)
Downhole sand exclusion is becoming an essential sandface completion concept for brown fields in Peninsular Malaysia Oil Fields as reservoir pressure declines and formation sand weakens with production and water breakthrough. Additionally, multi-stack reservoirs require good zonal isolation to prevent cross flow between reservoirs with different pressure regime and to ensure gas and water breakthrough is delayed as long as possible. As such, Cased Hole Gravel Pack (CHGP) is the preferred method in many Malaysian fields. However, a lot of marginal fields become uneconomic due to the high cost and complexity of CHGP. Therefore, reducing CHGP’s cost and time becomes vital to ensure that projects improve the economics while at the same time ensuring good productivity from the reservoir.
Traditionally, CHGP is performed zone-by-zone whereby the process of sump packer installation, perforation run, deburr run, gravel pack assembly installation and gravel pumping is repeated for each zone. In most cases, fluid loss pill which induces impairment of the formation is required. The paper will highlight on the Alternate Path System (APS) which enables single trip multiple-zone gravel packing whereby a repetitive process is only performed once. Gravel mixed continuously with low friction viscoelastic surfactant fluid allows for transportation to the lower zones via shunt-tubes attached to the screens even at extended shunt length. The APS system is then combined with Drill Stem Test (DST) and Tubing Conveyed Perforating (TCP) equipment to make a whole system of Single Trip Multizone Perforation and Pack (STPP)
STPP technology was deployed in a campaign of four deviated and high temperature oil wells in a marginal field whereby the rig time saving was up to three days per well translating to almost USD 1 MM of cost saving which boosted project’s economics. Furthermore, STPP technique allows for gravel packing operation without fluid loss pill and less completion fluid loss in the formation which translates to better formation productivity and less impairment.
Premature setting of GP Packer in one of the wells due to rupture disc failure within STPP system is the first such occurrence in the world. A lesson learned on how to ensure that it will not be repeated will be shared with all attendees.
Choudhuri, Amit (PETRONAS Carigali Sdn Bhd) | Jainal, M Saifunazim B M (PETRONAS Carigali Sdn Bhd) | Adenan, Mustafa (PETRONAS Carigali Sdn Bhd) | Takei, Jamaludin B (PETRONAS Carigali Sdn Bhd) | Ali, Toslan B (PETRONAS Carigali Sdn Bhd) | Janor, M Nazori B (PETRONAS Carigali Sdn Bhd)
An innovative work process for integrated and collaborative way of working has been developed and is being operationalized throughout all PETRONAS Carigali operating blocks, within Malaysia and also, in all International Countries wherein PETRONAS Carigali is the operating partner. This process is inline to the Company's vision for a phenomenal shift in the way that the company's workforce accomplishes its tasks, employing latest digital technologies and efficient work processes. Through this work process, the intention is to integrate all systems and tools, adopt collaboration between various work disciplines and come up with a novel work process that is lean with the prime objective of maximizing production and improving the production efficiency.
This integrated and collaborative work process is being named as Reservoir Well Facility Management (RWFM), encompassing all the six production lenses and is thus an end-to-end business process. The geographical areas of operation of the Company are vast and scattered across the world. Thus, a need has been felt to standardize the work practices across all operating blocks in order to ensure that there is a standardized and integrated way of working at every work location. Also, there have been a number of digital solutions deployed over the last couple of years and the immediate need is to integrate all these solutions as well as to enhance their utilization. This RWFM work process will facilitate increased utilization of the tools as well as integrate all the current solutions.
The new work process has been deployed as a program at most of the Assets of the Company. The process will take some time to be fully practiced and the program team will be looking at a stabilization period before the Assets actively implement it in their daily routine. There is a Change Management effort ongoing in parallel to assist the operationalization team and to bring in the mind set change to inculcate the new way of working. This paper will entail a detailed discussion on the work process and the operationalization activity undertaken by the focused team.
Ismail, Syahezat (PETRONAS Carigali Sdn Bhd) | Sy Rahim, Sy Puteh Mariah (PETRONAS Carigali Sdn Bhd) | Yahia, Zaidil (PETRONAS Carigali Sdn Bhd) | Elshourbagi, Saied Mustafa (PETRONAS Carigali Sdn Bhd) | Ishak, M Faizatulizuddin (PETRONAS Carigali Sdn Bhd) | Roslan, M Rizwan (PETRONAS Carigali Sdn Bhd) | Che Hamat, W Afiq Farhan (PETRONAS Carigali Sdn Bhd) | Ben Amara, Abdel (Silverwell Energy) | Faux, Stephen (Silverwell Energy) | Makin, Graham (Silverwell Energy)
Moving to digitalization era in the current low oil price environment, paradigm shift is really crucial in managing brownfield development and production. The challenge is to select the best technology to harvest the optimum production from the field but at the same time reduce potential capital and operating expenditure.
The paper highlights the technology evaluation of Digital Intelligent Artificial Lift (DIAL) system. This includes it's working principles, candidates screening, risk mitigation plan as well as technology success criteria developed specifically for the technology.
DIAL system is an in-well gas lift system that can overcome the well design and operational limitations of existing side pocket mandrels and valves. DIAL enables a better gas lift well design as well as able to interconnect downhole and surface monitoring & control in real-time. It provides opportunity for automation, better subsurface and surface integration as well as minimizing well intervention requirement.
Based on the promising technology evaluation, one pilot well was identified by the team at DL field. The well was part of DL drilling campaign executed in Q2 2018. Details of the well design & scope, as well as gas lift design for the well will be shared. Commercial comparison was demonstrated between conventional side pocket mandrel system and the DIAL system.
The case study at DL field will be discussed in details, starts from their wells’ design, technology deployment strategy, installation, production test result as well as lessons learnt during installation and operationalization of the system.
Moving forward from the pilot application, root cause failure analysis was done, lessons learnt were identified, design improvements were proposed and continuous monitoring of the system will be done, according to the success criteria outlined. Potential replication candidates have also been identified by the team with at least 10 promising potential candidates to be installed within the next 2 years.
The technology deployment was the result of collaborative works between PETRONAS, Silverwell Energy and Neural Oilfield Service.
Tugimin, M Azri Aizat (PETRONAS Carigali Sdn Bhd) | Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Baghdadi, Faical (PETRONAS Carigali Sdn Bhd) | Gupta, Anish (PETRONAS Carigali Sdn Bhd) | Mohammad Azili, Ammar (Schlumberger) | Mohamed Hanafi, Muhammad Mukrim (Schlumberger) | Meza, David (Schlumberger)
Sand Monitoring workflow was introduced in R field to manage and minimize the risk that sand production poses to the production facility by monitoring the sand production and its resulting erosion rate, and raise alarm immediately when these conditions violates the allowable threshold. The workflow serves as an enabler to the sand management process that are put in place at the field. By leveraging the automation from IO and complement it with additional processes, we came up with a holistic approach that is used to minimize the risk to the production facility. The defined Sand Management methodology starts with the automated workflow processing. The workflow utilizes data from field sensors and processes them to conduct risk assessments, and some mathematical calculation that are based on proven correlations. Based on these processes, the workflow will generate output of sand production risk assessment, calculated erosion rate, estimated remaining pipe thickness as a result from the erosion rate and critical drawdown monitoring.
To complement the output from the workflow, additional processes that utilizes the outputs are introduced as part of the sand management process. Some of these additional processes are: Correlation calibration by comparing the estimated pipe thickness from the workflow against computerized radiography or unit thickness manual measurement. Conduct Sand Depositional modelling at the high-risk location identified from the workflow to optimize sand handling capacity and monitoring. Extend the monitoring by utilizing network modelling software to assess the erosional risk from interlink of pipelines between jackets. Choke health monitoring and estimation based on choke CV and modelling.
Correlation calibration by comparing the estimated pipe thickness from the workflow against computerized radiography or unit thickness manual measurement.
Conduct Sand Depositional modelling at the high-risk location identified from the workflow to optimize sand handling capacity and monitoring.
Extend the monitoring by utilizing network modelling software to assess the erosional risk from interlink of pipelines between jackets.
Choke health monitoring and estimation based on choke CV and modelling.
The sand monitoring workflow has increased personnel efficiency by automating repetitive and tedious work and give out the result in an easily interpreted manner. The automated alarm has been proven to be useful in proactively engaging operations to tackle the problematic matter. Production interruption related to sand production has been effectively reduced by 50% after the implementation of the new Sand Management methodology.
The introduction of the workflow into the new methodology uses marginal cost, but maximizes the return on existing asset through the realization of their production potential, as well as proving on how multidisciplinary integration and collaboration between operator and the service company can be successful in a mature field despite the risk associated.
Kumaran, Prashanth Nair (PETRONAS Carigali Sdn Bhd) | Charbernaud, Thierry (Schlumberger) | Ibrahim, Ramli (PETRONAS Carigali Sdn Bhd) | Kadir, Zairi (PETRONAS Carigali Sdn Bhd) | Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Yaakob, Mohd Taufiq (PETRONAS Carigali Sdn Bhd) | Mandal, Dipak (PETRONAS Carigali Sdn Bhd) | Ataei, Abdolrahim (PETRONAS Carigali Sdn Bhd) | Maldonado, Jorge (Schlumberger) | Abdul Rahman, Mohd Ramziemran (Schlumberger) | Iskenova, Gulnara (Schlumberger) | Ceccarelli, Tomaso Umberto (Schlumberger) | Djarkasih, Fredy (Schlumberger) | Abdul Rahman, Nor Nabilah (Schlumberger) | Mohd Salim, Ahmad Syahrir Hatta (Schlumberger) | Moreno, Juan Carlos (Schlumberger) | Cavallini, Alberto (Schlumberger)
A West Baram Delta prolific mature oil field has been developed through 150+ wells since 1975 in Malaysia. In 2015, an exploration well drilled in neighboring block, successfully found ~500ft TVT of gross oil, 50% less than expected due to structural changes. With lower than expected hydrocarbon in place, the project team was forced to re-evaluate the development and identified key strategies to minimize the number of wells to drill while ensuring healthy project economics. Optimizing reserves and ensuring future accessibility while minimizing number of wells and cost, were the key challenges. Rather than developing all sands with highly deviated well, the team designed an extended reach horizontal well targeting a single key reservoir containing 60% of block STOIIP. Team decided to drill from an existing platform with no pilot hole but opted for real time reservoir mapping technology for well placement. The well was designed with no smart completion due to surface power limitation. First time in the region a dual defensive sand control mechanism was selected, Gravel Pack & Sand Screens. The 1st ever horizontal well was drilled S field meeting its objective at Q4-2017 and exceeding forecasted initial rates. With a long horizontal open hole section and being the only well in the block, a major challenge was to delay water coning and to control water cut once water breaks through. This was achieved with the installation of 8 Inflow Control Devices (ICDs). Real-time reservoir mapping while drilling was used successfully to land the well and then optimize the production section in good quality sands despite structural uncertainty. The well, designed with 60° maximum inclinations, ensures routine well intervention to be done using slickline (i.e. gas lift valve change). Any major intervention would still require coil tubing with usage of barge. The horizontal profile overcomes the limitation of power supply for automation that would be faced with high angle deviated well hence saved significant surface modification cost. The out of box solution of optimized field development plan for complex offshore Brownfield with limited facilities modification, while being cost conscious but technically sound concept proven to provide the answer for sustainable production growth in S Field at low oil price environment. The success of this well has changed the team mindset to relook and propose similar design wells in previously deemed uneconomical FDPs within the S Field.
Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Kadir, Zairi (PETRONAS Carigali Sdn Bhd) | Kumaran, Prashanth Nair (PETRONAS Carigali Sdn Bhd) | Ibrahim, Ramli (PETRONAS Carigali Sdn Bhd) | Ahmad, Mior Yusni (PETRONAS Carigali Sdn Bhd) | Madon, Bahrom (PETRONAS Carigali Sdn Bhd) | A Aziz, Adam Hareezi (PETRONAS Carigali Sdn Bhd) | Ishak, Mohd Faizatulizuddin (PETRONAS Carigali Sdn Bhd) | Gordon Goh, Kim Fah (Schlumberger) | Ceccarelli, Tomaso Umberto (Schlumberger) | Tan, Chee Seong (Schlumberger) | Kalidas, Sanggeetha (Schlumberger) | Mohd Salim, Ahmad Syahrir Hatta (Schlumberger) | Maldonado, Jorge (Schlumberger) | Lei Min, Zhang (Schlumberger) | P Mosar, Nur Faizah (Schlumberger) | Gil, Joel (Schlumberger) | Abdul Rahman, Mohd Ramziemran (Schlumberger) | Watana, Kulapat (Schlumberger) | Chabernaud, Thierry (Schlumberger)
The first horizontal oil well was drilled through an anticline structure in the Block-7E of East Flank, S-field, penetrating three production sands Sand I, Sand II and Sand III. Based on a comprehensive pre-drill study through steady-state and 3D dynamic time lapse simulation, Inflow Control Device (ICD) with integral sleeve (on/off function) attached to the ICD's joint is the optimum development of the fault block that maximizes zonal control for contrasting water encroachments. Due to the unconsolidated nature of the target reservoir, this well is designed for Open-Hole Gravel Pack (OHGP) with specialty 3D filtration screen to manage sanding issue. This paper highlights 2-in-1 application of ICD with enabled zonal shut-off sleeves and the OHGP completions with external screen. A pre-drilled ICD dynamic modeling is constructed to evaluate the well performance with ICD configuration. The design criteria for an optimum ICD design configuration is based on number of compartments and size, packer placement, ICD nozzle sizes and numbers. This dynamic single well model was used to justify the technology value which resulted in production improvement (maximizing oil and minimizing/delaying water). However, during the drilling of this well, the pre-drilled model is then updated in real time with the input of actual petrophysical data from Logging While Drilling (LWD) measurements along the OH section. Actual well trajectory and structure adjustment encountered while drilling were also co-utilized to determine the final optimum ICD design for the field run-in-hole (RIH) completion. Target fault block in S-Field East Flank requires optimum development strategy for its economic viability (
Mohd Hatta, Siti Aishah (PETRONAS Carigali Sdn Bhd) | Zawawi, Irzee (PETRONAS Carigali Sdn Bhd) | Gupta, Anish (PETRONAS Carigali Sdn Bhd) | Ahmad Nadzri, M. Safwan (PETRONAS Carigali Sdn Bhd) | Salleh, Nurfarah Izwana (PETRONAS Carigali Sdn Bhd) | Jeffry, Suzanna Juyanty M. (PETRONAS Carigali Sdn Bhd) | Sharif, Natasha Md (PETRONAS Carigali Sdn Bhd) | Ishak, Izza Hashimah (PETRONAS Carigali Sdn Bhd) | Maoinser, M. Azuwan (Universiti Teknologi PETRONAS)
Field B is a marginal green field located offshore Sarawak, Malaysia with formation depth of less than 1000 meters. The compressional sonic transit time range is from 100 – 115 μs/ft, which immediately triggered the possibility of using active downhole sand control as this range is assumed to be unconsolidated. However, the rock mechanical strength characterization tests from sidewall core indicated contradictory result of a consolidated formation. Since the field is considered as a small field, the cost of the well especially on downhole sand control device need to be extensively optimized. Hence, sand prediction study for a small green field development using field and laboratory measurements was performed.
Several methodologies of sand prediction were utilized to evaluate the optimum sandface completion and sand control management for the field. Empirical and analytical sand prediction based on the well logs, sidewall cores analysis, and sand prediction software are employed to evaluate the likelihood of sand production and the optimum well completion design for the field development. The available data from appraisal wells of Field B is also calibrated to the nearby brown field, Field A that has been producing for more than 30 years.
This paper will discuss on the sand onset prediction results between full perforation versus oriented perforation, and pressure depletion impact on the sand production. The study shows that the formation is not prone to sand production especially in the early part of the production life with high reservoir pressure and low watercut. The expected Critical Drawdown Pressure (CDP) generated from different methods show large variation of sand onset pressure if the sandface is completed using full perforation. Oriented perforation tremendously expands the sand free drawdown limit. Based on the results of the study, expected reservoir pressure depletion and watercut, the completion of the wells adopted Oriented Perforation with no other downhole sand control equipment.
This paper is beneficial for petroleum and well completion engineers especially on sand prediction part of well completion design in development stage. This will assist in ensuring the field meets the EUR and bring forward economic value as well as well integrity assurance.