As of early 2017, PETRONAS has approximately 40% of aging platforms & pipelines that aged more than 30 years. As a party to UNCLOS, Malaysia is legally bound to undertake Decommissioning of its asset. Internally, apart from PETRONAS’ existing Procedure and Guideline for Upstream Activities (PPGUA) that spell out the recommended decommissioning principles, PETRONAS has devised a new set of decommissioning review process, known as Abandonment Review (AR) to ensure PETRONAS get the optimum levels of assurance its require from the operator/contractor. The deliberation of every decom project application is according to the type of scope of works which covers wells plug & abandon, pipeline/floaters or integrated facilities.
Following the downturn in crude oil prices and major decline in oil production for some of its fields, PETRONAS had to further evaluate and finally decided to decommission one of its Small Field Risk Service Contract (SFRSC) field, specifically Kapal Field. Upon PETRONAS’ review & approval process completed, execution phase commenced with the least complicated scope of work, which consist of Plug & Abandon (P&A) of 4 wells, detachment of wellbay support structure (WSS), retrieval of mooring chains, anchors and flexible pipeline, and relocation of MOPU for warm stack/cold stack purposes. However, during Project Risk Assessment exercise, relocation of MOPU was identified as one of the critical path as it involves integrity of the existing MOP and as such posed a high risk to the whole cost and schedule of the project.
Since decommissioning of upstream facility consider as a niche subject in Malaysia, educating of various internal and external stakeholders was required in order to establish the key steps for the decommissioning execution. Liaising with related state agencies was done through Exclusive Economic Zone sitting, with Petroleum Safety Unit's (PSU) as the secretariat. PSU is one of the unit under Ministry of Domestic Trade, Cooperative and Consumerism (MDTCC) which responsible in coordinating the policies, licensing, regulations and activities related to the safety of petroleum, petrochemical and gas industry in Malaysia.
There were plenty of great experiences and important lessons that PETRONAS learned in this project which PETRONAS thought worth to share with the industry. PETRONAS believes that through each successive failure in what we're doing, our values were reshaped. Even though this decommissioning activity was a schedule-driven project, cost optimization always becomes the key condition for making project management decisions. Not to mention on PETRONAS’ aspirations to contributes to sustainable development by delivering economic, social and environmental benefits for all stakeholders, collaboration and Memorandum of Understanding (MOU) achieved between PETRONAS and Department of Fisheries (DoF) in Rig-to-Reef Program had opened up a new perspective on how PETRONAS’ decommissioning activities can contribute towards its corporate social responsibility (CSR) program.
Subsea separation and produced water re-injection (PWRI) or discharge has long been considered as an enabling technology for developing deepwater / ultra deepwater and marginal fields. It is an integral part of the subsea processing strategy which brings many economical, operational and environmental benefits for the offshore Oil & Gas industry. However, one of the key technology gaps remaining is in relation to water quality measurement for subsea separated produced water. This review is based on JIPs that NEL has conducted and its recent involvement in a RPSEA project. The review also includes progress made by operators and vendors.
Existing practice for subsea water quality measurement involves in sending an ROV (Remotely Operated Vehicle) to take a produced water sample and then bring it to surface for analysis. This practice is extremely expensive, time consuming and not good for operations. The technology gap has in many ways prevented the widespread of using subsea separation and produced water re-injection systems.
Good progress has been made in developing a subsea water quality measurement device in recent years. This has been achieved through a combination of efforts by operators, government bodies, vendors and independent organizations. Technologies that have the best potential for subsea applications include: Light scattering; Microscopy imaging; Laser Induced Fluorescence; Ultrasonic acoustic.
Laser Induced Fluorescence;
Most of the above-mentioned technologies are currently surface proven. They are of Technology Readiness Level (TRL) of 3 in relation to subsea applications, which means that they are prototype developed, function and performance assessed. Some of the key progresses to date are resulted from the use of LED as a light source, better fouling mitigation approaches, purposefully conducted lab and surface field trials. Further progresses are anticipated in which some of the mentioned technologies will be developed to TRL 4 (environmental tested) and TRL 5 (system integrated).
There are currently very few references in the literature on the subject. This paper will add valuable information to the public domain regarding the status of the development of subsea produced water quality measurement sensors.
Permanent environmental damage cannot be compensated in terms of money. Unfortunately, oil spills contaminate water, restraining marine species of their habitat and food supply. Despite the numerous methods available today to clean up the water body affected by an oil spill by separation of oil and water, none have restored water to its previous quality or saved marine animals from its deleterious effects to the full extent. The biggest hurdle to this cause is the sunken oil; the oil which may have either sunken mixed with sand and mud or by dispersion due to weathering.
Ferro fluids are Fe3O4 based Magnetic Nano Particles (MNPs) which can be coated with a layer of polymer or surfactant to form a super-hydrophobic material which selectively adsorbs oil. This work involves coating the MNPs with Polyvinyl-pyrrolidone Styrene and Sodium Oleate. These colloidal ferromagnetic Nano-particles display considerably higher magnetic susceptibility. The MNPs are non-toxic nano sized sponges that sink deep inside the water body, adsorb 10 times their weight of oil and float back to the surface. It must be well-known that electrostatic attraction between negatively charged oil-in-water emulsions and positively charged MNPs controls the attachment of MNPs to the droplet surface; and the subsequent aggregation of the electrically neutral MNPs-attached oil droplets shows a critical role for accelerated and capable magnetic separation.
During the experimental work performed, it was seen that after separating out the recovered oil, the MNPs can be regenerated and re-used. In this work, a 1-D mathematical model was developed for describing the dynamics of the action of the MNPs for oil spill cleanup and its collection in the framework of the sedimentation theory. The model was based on Newton's law of Motion, theory of batch sedimentation, Settling velocity and Stokes-Einstein equation. In order to completely understand the process and to formulate a model that correctly and aptly mimics the experimental observations, the conservation equation for MNPs was also coupled with the flux function, which accounted for gravity force, magnetic force and Brownian interaction. Parameters like offshore constraints and weather conditions were considered while running the model, to make the model more robust, as well as to observe the impact on final obtained results.
Bunkering and oil storage is a growing and important business in Singapore. Driven by land scarcity, NUS and SINTEF are tasked to jointly explore the innovative concept of a Floating Hydrocarbon Storage and Bunkering Facility (FHSBF) off the coast of Singapore. The research collaboration, funded by Land and Livability National Innovative Challenge (L2 NIC) and JTC Corporation, aims to explore new ways to create useable space from sea. The floating facility will add to the current storage capacities of Singapore without the need for land reclamation. The Floating Hydrocarbon Storage Facility is a novel and viable concept to introduce useable space on sea. It allows for a land-scare country like Singapore to increase oil storage capacities without the need for land reclamation. The concept can be relocated and replicated in other locations with similar needs.
Novel well completion technique is used to ensure dual tubing performed under fatigue condition in Field B TLP. Based on initial tubing stress analyses, the dual strings are under compression during production. Also due to the Single Combo Top Tension Riser (SCTTR) design, first in the industry, the riser must be isolated from hydrocarbon flow. All 10 producers completed to date were tensioned successfully using this technique. This paper discusses various methods of string tensioning and executing the completion.
Gas hydrate has been found both in the permafrost and deep ocean in China. However, due to easier access, much lower well cost and proximity to existing gas pipelines, gas hydrate in the permafrost is more attractive for commercial development. In this paper we examine the published data on gas hydrate exploration in various Chinese permafrosts, identify the key technical challenges and suggest directions for future study.
Our study has identified Qilian Mountain Permafrost, Mohe Basin and Qinghai-Tibetan Plateau as the three permafrosts with highest potential for gas hydrate development. Of the three, only Qilian has confirmed occurrence of gas hydrate by coring. From the perspective of field operations, Qilian ranks highest in potential for development due to its proven hydrate occurrence, thickness of hydrate bearing layer and proximity to existing gas pipelines. Mohe ranks second due to its benign operating conditions. However, it lacks existing gas pipelines. Qinghai-Tibetan Plateau ranks third due to its high elevation which limits access and lack of oilfield infrastructure.
We found that the key subsurface uncertainty is the gas hydrate saturation. There is little information on it for all three permafrosts. Other subsurface uncertainties include the thickness of the permafrost, geothermal gradient beneath the permafrost, porosity, gas hydrate composition and permeability of the hydrate-bearing layer. Future research needs to determine these reservoir properties accurately.
Examination of core samples and logs from Qilian shows that gas hydrate distribution is discontinuous both vertically and areally. Therefore, a better way to quantify the uneven hydrate distribution in the reservoir is needed for reservoir engineering calculations.
Current estimates of well production rate by reservoir simulation are sub-commerical and probably due to the assumption of pure methane hydrate which limits the thickness of the gas hydrate stability zone. Also, the assumption of using horizontal wells for hydrate production may be optimistic due to shallow depths and the discontinuous nature of hydrate distribution. Consequently, new recovery methods besides depressurization and thermal stimulation will be needed to increase the well production rate.
Furthermore, we have identified a number of similarities in production engineering aspects of gas production from hydrate and coalbed methane (CBM) wells. Common challenges include reservoir depressurization by water production, solids production, need for artificial lift and difficulty in drilling long horizontal wells in shallow reservoirs. Therefore, some best practices from CBM production, such as pad drilling, artificial lift and water treatment methods, may be usable for gas hydrate production.
Wax deposition is one of the most expensive flow assurance issues encountered in crude oil production and transportation. It can lead to drastic production loss and ultimately heavy economic losses to E&P companies. Thus, precise prediction for field case is necessary to avoid this issue. Generally, two basic models, Film Mass Transfer (FMT) and Equilibrium Model (EM) are utilized to determine wax mass deposition in the crude oil pipelines. In this study, theoretical wax mass flux is computed based on these methods and compared with a field data point of wax mass deposited in 1.7 km long buried gathering line at Bakrol field, Gujarat, India. For a field flow rate of 100 m3/day in 4 in. pipe (ID = 3.765 in.), the fluid is in laminar flow regime. This contradicts the presumption that only turbulent flow condition prevails in the field. In addition to this, the analysis revealed that actual field wax mass flux for Bakrol field gathering line is close to the estimated value using FMT model and not EM. This agreement of the field data with laboratory flow loop data might be due to the closeness of field pipe ID (3.76 in.) with flow loop pipe ID (0.5 to 2 in.). Therefore, for Bakrol field, it is suggested to use FMT model for the calculation of wax mass flux rather than the EM model. However, previous researchers have reported predictions from FMT model also holds true for turbulent flow conditions in field case, which is in contradiction with the observation and explanation available in the literature for laboratory scale flow loop data. Thus, field data with larger diameter pipe and different waxy crude oils are required to make a robust conclusion.
Carbonates are often drilled with aggressive drill bit features such as sharper PDC cutter chamfers and lower backrakes of the cutters. Bit aggressiveness features can produce higher penetration rates through hard carbonates, but the potential for increased wear can be detrimental over long intervals.
A field in the Timor Sea, offshore Northern Australia, has an 1800m surface hole interval where the chosen drill bit design must be capable of drilling a long carbonate section, prior to intercepting a hard, interbedded section. After this section, there is another long carbonate formation before casing point. Sustaining any slight cutter edge dulling can dramatically affect the penetration rate potential in the interbedded section, and the bit's ability to drill the post interbed section.
Hybrid technology in 17.5" hole size was recommended for this field during a 2014 drilling campaign due to its increased durability through interbeds as compared to conventional PDC technology. This durability was seen in offset fields in the region, and had resulted in performance advantages and time savings.
The new hybrid bit was used on the first well with success, drilling the interval in one run, as compared to the 2-3 bit runs seen on prior wells in the region when using conventional PDC and TCI technology. With learnings from this first well, a design change was implemented which saw the hybrid TCI cones employ a sparser wedge heel instead of ovoid heels. These modifications saw minimal change in performance on the later wells. From the 2014 campaign results, a recommendation was made to increase the insert heel aggressiveness. Development and improvement in insert carbide grades during 2015-2016 led to the capability and introduction of increased integrity and aggressiveness with conic geometry inserts introduced to hybrid TCI cutting structures. New hybrid designs with the sharper and higher density insert cutting structure were used in offset fields and showed strong performance improvements.
During the most recent 2017 drilling campaign, the sharp conics and dense insert cutting structure layout of the new Hybrid product line was applied in the Timor Sea and mirrored the performance advantages seen on offsets. A previous interval best time of 73.2hrs in 17.5" hole was reduced to just 37.7hrs with a sharp and dense hybrid design and to just 26.3 hours with a 16" hybrid utilising the new design features, reducing time taken to drill the interval by 50% and 65%.
This paper illustrates the design history, lessons learnt, and differences in insert geometry and how this contributed to the improvement in penetration rate in a challenging application.
The ability to detect, evaluate and model thinly laminated formations, as well as to include the sand portion in the reserve calculations, has continuously been a challenging task for oil and gas service and operation companies. This challenge is directly attributed to two reasons:
The big difference between the conventional log's vertical resolution (6 inches and above) and the thickness of these beds (sometimes less than 1 inch); and The direct influence of the low resistivity shale laminations within these thin sand laminae on supressing the resistivity reading (thus masking the existing thin sand laminae, which may be oil prone)
The big difference between the conventional log's vertical resolution (6 inches and above) and the thickness of these beds (sometimes less than 1 inch); and
The direct influence of the low resistivity shale laminations within these thin sand laminae on supressing the resistivity reading (thus masking the existing thin sand laminae, which may be oil prone)
Many efforts in the industry to characterise these thinly laminated reservoirs were put together. Yet, all the existing approaches experience some uncertainty in their results. Most of the industries current approaches contain drawbacks due to certain assumptions involving i thin beds analyses, resulting in high uncertainty. Thus, new technology is needed to improve development and production from these reservoirs.
In this research, wells from 4 fields in both Malay Basin and Sabah Basins, with over 4000 feet of core analysis, full sets of conventional logs and over 5000 feet of different types of micro-resistivity image logs were used. New methodology to calculate true resistivity at a vertical resolution of 0.1 inches was introduced in both oil and water-based mud. A modified alpha processing approach solves the mud influence by introducing a new projecting factor.
New methodology to calculate high resolution density and neuron porosity was also introduced to be used with high resolution resistivity log and to conduct full reservoir evaluation using the high-resolution logs. This includes calculating lithology, porosity, permeability and water saturation at the resolution of 0.1 inch. Calibration of the results with core data and core plug tests supported the findings and showed that the new evaluation using the high-resolution logs is better at matching the core tests than the currently available methods. Thus, this novel approach can be used to evaluate thin beds in any environment and using any type of micro-resistivity images.
Gas hydrate formation poses a significant threat to the production, processing, and transportation of natural gas. Accurate predictions of gas hydrate equilibrium conditions are essential for designing the gas production systems at safe operating conditions and mitigating the problems caused by hydrates formation. A new hydrate correlation for predicting gas hydrate equilibrium conditions was obtained for different gas mixtures containing methane, nitrogen and carbon dioxide. The new correlation is proposed for a pressure range of 1.7-330 MPa, a temperature range of 273-320 K, and for gas mixtures with specific gravity range of 0.553 to 1. The nonlinear regression technique was applied to develop the correlation based on 142 experimental data points collected from literature, validated with 85 data points not used for developing the correlation. The statistical parameters analysis showed an average absolute error (AAPE) of 0.2183, a squared correlation coefficient (R2) of 0.9978 and standard deviation (SD) of 0.2483. In addition, comparing the new correlation results with the experimental data and with those calculated by other correlations show an excellent performance for the investigated range.