Critical drawdown pressure for sand onset and its accuracy with change in water cut is a continuous area of study. The numerous parameters like grain cementation, viscosity of fluids, actual physics of sand production with fluids leads to a lot of uncertainty. In practical terms, it has been observed that these mechanisms lead to reduction in Uniaxial Compressive Strength of rocks. The objective of this paper is to present a novel method that not only helps on understanding the effect of water production on sand failure but to further predict the volumetric expected sand production up until a certain tolerable error.
A sand prone field within Malaysian region was identified and core tests were done to evaluate UCS and other rock strength parameters at different saturation of water to simulate the effect of water on rock strength. CDP evaluations were done and the values were calibrated with actual field data to have an accurate understanding of CDP values at different water cuts. Lastly, with the findings from field production data, limit was pushed further to develop a novel method to predict the volumetric sand production.
The proposed novel method has helped not only in understanding the effect of water production on sand failure but also on the amount of sand to be produced under different drawdown pressures with a reasonable accuracy. These results proved very useful in implementing Company's Holistic Sand Management strategy. The integration of this method with water cut predictions from reservoir simulation models helped the team to quantify the continue increasing sand production due to water cut increase. Company is replicating similar workflow in other sand prone fields for an effective sand management.
The approach is very novel as the theoretical modelling work has been effectively calibrated using real field data. This method has provided a high degree of confidence in estimating the amount of sand to be produced under different production conditions.
Authors consider this as a breakthrough in field of holistic sand management and very useful workflow for all other operators to emulate.
This paper will discuss further on the recent decommissioning project of fields which has been completed on November 2017. These two platforms had been totally removed and became an artificial reef at Sarawak water in Malaysia. This paper will show the activities and best practices; the team had gone through from early stage until completion of the process based on the decommissioning phases. The decommissioning framework consists of five phases starting from Late Life Planning and Preparation; Regulatory, Compliance and Permitting; Facilities Hook-down and wells make safe; Removal and Remediation and lastly, Post Remediation. In baseline inspection, the underwater inspection had provided some information to the contractor on the scope and revealed some of the uncertainties about the decommissioning project. On an important note, an engineering study is critical to ensure safe operation. After our observation, we noted that actual operation is similar to the engineering's simulation where the team had to follow the engineering accordingly. Reefing engineering crucially needed to be performed to ensure the facilities been placed at the right location and position. During offshore execution removal of facilities, there were challenges we faced such as malfunction of the cutting/dredge equipment which led to a back up plan and innovative solution. We had to utilize other available equipments available onboard (Diamond wire cutter, abrasive waterjet internal cutter, dredger, soil plug removal, airlift, cutting torch etc.). Selection of cutting tools also needed to be considered to minimize the pinch effect of the facilities. Finally, Post decommissioning survey had been carried during the Post Remediation phase to assess the successful of the project. The post-decommissioning/reefing survey had been carried out and the result observed new marine growth and numbers of fishes at the reefed platform. It had been concluded that this decommissioning reefing project was successful. This paper should be an interest to those who will be exploring abandonment and decommissioning project which includes reefing as one of the decommissioning options. This paper will also show on decommissioning process through Engineering, Preparation, Removal and Disposal (EPRD) approach contract. The novelty in this paper is on the assurance that had been made by Company via baseline and post reefing survey to ensure environment aspect had been considered.
Hydraulic fracturing stimulation is considered a successful development technique in tight gas reservoirs. However, these expensive operations sometime underperform due to ineffective fracture fluid (FF) clean-up. This paper concentrates on FF clean-up efficiency for a Multiple Fractured Horizontal Well (MFHW) completed in both homogeneous and naturally fractured (NF) tight gas reservoirs. The emphasis is on NF reservoirs that make up a large percentage of tight gas assets, as their clean-up efficiency has received little attention.
In this study, two numerical simulation models, i.e. a single-porosity single-permeability and a dual porosity-dual permeability model representing a homogeneous and a NF tight gas reservoir respectively, were used. Simulations were conducted on a MFHW with seven hydraulic fractures (HF). The process comprised of injection of FF, then a soaking time (ST) followed by production. The impact of various parameters which includes ST, FF viscosity, pressure drawdown and parameters pertinent to relative permeability and capillary pressure in matrix, hydraulic and natural fractures, were evaluated.
In addition, based on a newly proposed treatment process that generates in-situ pressure and thermal energy that breaks gel viscosity, the effect of resultant viscosity reduction and local pressure increase, for improving the clean-up efficiency was also assessed. In these simulations, and due to uncertainty in its value, NF permeability was varied over a wide range. For conclusive purposes, Gas Production Loss i.e. GPL (%) defined as the difference in total gas production between the completely clean and un-clean cases as a percentage of the clean case, after a specific production period was used. This paper prioritizes the impact of pertinent parameters and highlights the influence of thermochemicals on the clean-up efficiency thereby justifying its commercial practicality. For instance, it is shown that the presence of NFs results initially in higher GPL but then GPL reduces significantly. Reducing the FF viscosity improves clean-up significantly especially for the NF models as NFs are the main contributor to the gas and FF flow from the reservoir to surface via hydraulic fractures. The sometimes non- monotonic trend of GPL variations, depends on the specific combination of NFs’ permeability and FF viscosity which results in the certain fluid invasion profile and mobility in the system.
The paper emphasis is on the impact of thermochemicals and natural fractures on the cleanup up efficiency of hydraulic fracturing stimulations that should be optimized to reduce cost, thereby increasing the profit from these projects.
Gong, Jiakun (Delft University of Technology) | Vincent-Bonnieu, Sebastien (Shell Global Solutions International B.V.) | Kamarul Bahrim, Ridhwan Zhafri (Petronas) | Che Mamat, Che Abdul Nasser Bakri (Petronas) | Tewari, Raj Deo (Petronas) | Groenenboom, Jeroen (Shell Global Solutions International B.V.) | Farajzadeh, Rouhollah (Delft University of Technology and Shell Global Solutions International B.V.) | Rossen, William R. (Delft University of Technology)
Surfactant alternating gas (SAG) is often the injection strategy used for injecting foam into a reservoir. However, liquid injectivity can be very poor in SAG, and fracturing of the well can occur. Coreflood studies of liquid injectivity directly following foam injection have been reported. We conducted a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a SAG process in the field (i.e., after a period of gas injection). Our previous experimental results suggest that the injectivity in a SAG process is determined by propagation of several banks. However, there is no consistent approach to modeling liquid injectivity in a SAG process. The Peaceman equation is used in most conventional foam simulators for estimating the wellbore pressure and injectivity.
In this paper, we propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of our experimental findings. The model represents the propagation of various banks during gas and liquid injection. We first compare the model predictions for linear flow with the coreflood results and obtain good agreement. We then propose a radial-flow model for scaling up the core-scale behavior to the field. The comparison between the results of the radial-propagation model and the Peaceman equation shows that a conventional simulator based on the Peaceman equation greatly underestimates both gas and liquid injectivities in a SAG process. The conventional simulator cannot represent the effect of gas injection on the subsequent liquid injectivity, especially the propagation of a relatively small region of collapsed foam near an injection well. The conventional simulator’s results can be brought closer to the radial-flow-model predictions by applying a constant negative skin factor.
The work flow described in this study can be applied to future field applications. The model we propose is based on a number of simplifying assumptions. In addition, the model would need to be fitted to coreflood data for the particular surfactant formulation, porous medium, and field conditions of a particular application. The adjustment of the simulator to better fit the radial-flow model also would depend, in part, on the grid resolution of the near-well region in the simulation.
Schlumberger has developed a unique PN-1 membrane technology in collaboration with Petronas. The technology is unique in combining two distinct types of membrane fibers in one single membrane module to reduce the overall membrane requirement by 10% and offers overall CAPEX and OPEX savings. The PN-1 technology was developed in 2009 and was successfully tested onshore and offshore facilities for total 5 years.
The PN-1 technology was first deployed in an onshore gas processing facility which was awarded to Schlumberger in 2013. The facility comprised of membrane pretreatment which is mainly gas dehydration, dew pointing followed by several PN-1 membranes in first stage. The membrane design was unique to handle variable inlet feed conditions from 25 to 12% CO2 inlet gas and outlet gas at 8% CO2. The feed gas design flowrate is 700 MMSCFD and at 750 psig operating pressure. Since this is an onshore gas receiving station, the processing trains should be able to handle variable inlet CO2 concentration in the inlet feed gas and particularly membranes.
Schlumberger engineered the entire pretreatment system, membrane and mercaptan removal system. The entire system was delivered and commissioned by Schlumberger on time and was brought online in 2017. The PN-1 membrane system was successful in meeting the required outlet gas CO2 specification while retaining maximum hydrocarbons in the product gas.
The Integrated Logistics Control Tower (ILCT) aims to enable vessel sharing across 15 Malaysia producing Petroleum Arrangement Contractors (PACs) to lower the logistics cost across upstream operations in Malaysia. Prior to this, each PAC operated their own vessels. Opportunities for synergy and sharing between PACs were rarely tapped resulting in fragmented demand and specification, which in overall leads to higher cost.
ILCT was triggered from a heuristic study in June 2016 and the study showed the potential of RM100 millions yearly cost saving from reduction of 10-20 vessels through fleet sharing across the producing PACs. A joint project management team was formed comprised of key logistics personnel from PETRONAS and PACs to execute ILCT. Operation simulations were conducted involving stakeholders from operations, Health, Safety and Environment (HSE), legal, finance, and procurements to identify current limitations, and the short, medium and long term solution in order to ensure such sharing will not compromise HSE and production performance.
The joint project management team has encountered multiple obstacles towards ILCT implementation such as vessel priority, marine HSE standardization, vessels technical specifications, joint coordination agreement, liabilities, cost allocation, accumulative contract value re-distribution, and governance matters. In overcoming the obstacles, the team has established ILCT Committee and ILCT Manual. The ILCT Committee comprises of PETRONAS and PACs members with the key roles to control the overall allocation of vessels, mediate any conflict, and improve ILCT performance. The ILCT Manual was jointly developed by PETRONAS and PACs to govern the implementation of ILCT and is regularly referred by PACs as guiding principle in operating vessels.
This national synergy resulted in 12 vessels reductions from 142 to 130 vessels that equivalent to RM100 millions of cost savings yearly. PETRONAS and PACs benefit from this synergy mainly through optimized traveling route, which results in lower Daily Charter Rate and fuel cost. It also supports PETRONAS’ agenda to nurture capabilities of local vessel owners to become regional vessel operators. The key success of ILCT lies on PETRONAS’ role as the regulator for Malaysia upstream industry, by orchestrating the cooperation across PACs in syncing the common alignment towards achieving the desired outcome of ILCT.
Malaysia's ILCT is the biggest integrated offshore marine transportation arrangement in the world, with 120 vessels involved in serving offshore transportation needs to 198 producing fields in East & West Malaysia.
Have we learned from historical major incidents in the industry?
We are working in a learning organisation equipped with structures and procedures to ensure that lessons from major incidents are incorporated as organisational changes. The following lessons were captured; apply HSE case regime; adapt process safety concept to drilling operations; create and sustain well integrity throughout the entire well life cycle and choose the right leading and lagging indicators to measure and promote continuous improvement.
The heart of these lessons learnt are to establish a process of managing the major accident hazard risks throughout well life cycle. In effect, identify hazards, define safety critical elements, develop performance standards and establish the assurance and verification process. Ultimately, the records of these steps have been demonstrated in safety case document. All steps have been monitored, tracked and audited through the Well Integrity Management System (WIMS). In execution, the conducted program was an assessment of our current situation, taking into account lessons learnt from historical major incidents, close gaps and sustain performance. The deployment was conducted through four distinct phases: Assess, Define, Intervene, and Sustain.
The outcomes of execution of the program in our wells stock are managing and preserving well integrity throughout well life cycle phases rather than operation phase only; the percentage of non-healthy wells are reduced from 25% in 2013 to 5% in 2015; all contracted rigs have verified HSE Cases; new well integrity measures are applied. Moreover, all are contained, tracked and audited in WIMS.
The application of WIMS combines technical, operational and organizational barriers to prevent the uncontrolled flow of fluids to the surrounding environments or across subsurface formations throughout well life cycle.
This paper will present the findings of a research project, and content of IPIECA's Practitioner Note on Monitoring and Evaluation of Social Investment (SI); which focus on the challenges faced by companies, considering increasing stakeholder demand for evidence-based reporting of social investment. The Note builds on the evolving experiences of practitioners in the oil and gas industry and the emerging and everevolving field of monitoring and evaluation (M&E). From 2015 - 2016 IPIECA undertook a research project to assess the content of its 2008 SI Guidance. While the research concluded that the principles of the Guidance remain valid and useful, it was also acknowledged that the document did not reflect the latest thinking on key SI issues and approaches. As a result, a series of Practitioner Notes were produced to present practical information on current industry practices on issues related to SI. The Notes were produced by collecting information through more than 50 telephone interviews with practitioners from IPIECA member companies and external stakeholders, as well as a literature review.
In order to design and analyse Alkaline Surfactant Polymer (ASP) pilots and generate reliable field forecasts, a robust scalable modeling workflow for the ASP process is required. Accurate modeling of an ASP flood requires detailed representation of the geochemistry and the saponification process, if natural acids are present. The objective of this study is to extend the existing models of ion exchange and surfactant partitioning between phases to improve the quality of the model.
Geochemistry and saponification affect the propagation of the injected chemicals. This in turn determine the chemical phase behaviour and hence the effectiveness of the ASP process. A starting point of such a workflow is to carry out ASP coreflood tests and history matching (HM) using numerical models. This allows validation of the models and generates a set of chemical flood parameters that can be used for forecasts. The next step is upscaling from lab to field. The presence of (geo)-chemistry in ASP model improves significantly the quality of core HM especially for produced chemicals, breakthrough time and their profiles shape.
The addition of surfactant partitioning between the oleic and the aqueous phases based on salinity of the system as well as propagated distance (time) improves understanding of the required surfactant concentration. The partitioning of surfactant is important for coreflood matching of native cores as they tend to have more clays and minerals that affect ASP phase behaviour. The upscaling of the HM coreflood was conducted in two steps. First step the coreflood was scaled up with the distance between injector–producer pair as the scaling parameter. Second step was the application of the scaled up injection rates, residual saturations, etc. to the full field model. Sensitivity study for parameters such as grid size, well distance, ASP slug size, and rate of surfactant partitioning was performed. It was found that grid size of 50ft was optimum for ASP modeling. The higher rate of surfactant partitioning resulted to lower recovery. The optimal well distance was determined as 700ft for optimization of oil recovery. The reduction of ASP slug size from 0.5PV to 0.3PV leads to the reduction in oil recovery by 2-3%.
Usually chemical reactions accompanied ASP process are left out of the model due to increase in complexity as well as longer computational time. However, their addition as well as presence of surfactant partitioning between the oleic and the aqueous phases makes ASP models more realistic and it results in significant improvement to coreflood HM quality and prediction of ASP process.
Lee, Jin Ming (Petronas) | Bt Mohd Zain, Siti Nur Mahirah (Petronas) | AB Malek, Anas B. (Petronas) | B. Nordin, M. Haikal (Petronas) | Rahaman, Ammar Thaqif B. A. (Petronas) | Hermawan, Heru (Petronas) | B. Nasrudin, Khairul Anwar (Petronas)
X-1 well is one of the wells from project X, a field development project located offshore Peninsular Malaysia. The well has become the signature well for project X as it managed to achieve single digit (in million dollar) well cost, a rare occasion for offshore Malaysia development wells. Project X wells team has taken several initiatives and strategies to reduce well cost and ultimately achieving low cost well (LCW) status as defined by the company's wells department.
Since year 2014, crude oil price has fallen from its heyday to as low as USD27 per barrel in 2015. Oil and gas (O&G) operators around the world have been struggling to make profit and fulfill their capital commitment. The company's wells department has since came out with criteria for LCW to be benchmarked by the company's projects. To be recognized as LCW, a well needs to be below USD 15 million with minimum depth of 1500 m and key performance indexes (KPIs) better than or equal to Malaysia Petroleum Management's (MPM) Drilling Minimum Standard without compromising operational safety, reserve development, well integrity and environmental aspects.
In the quest to achieve LCW, project X wells team has engaged several strategies to ultimately reduce X-1 well cost by 40% from initial estimated. These strategies involved the optimization of critical areas such as well design & engineering, well planning and operations.
After painstakingly planned and implemented above cost saving strategies within restricted time frame, project X wells team has successfully reduced 40% of initially estimated X-1 well cost. The reduction has proven that with focused planning and execution, coupled with full support from management especially with new contracting strategy, LCW is possible and able to help O&G operators to improve their bottom line. Low oil price environment has appeared to be the silver lining in O&G operators’ efforts to drive down cost as it appears to provide the opportunity for operators to re-evaluate their current contracts, planning and operation practices.