Leadership in Health & Safety – Driving Cultural Change in an Offshore Fleet
Maintaining a strong culture of safety presents numerous challenges to the leaders that operate within our organization.
This paper will demonstrate the methodology that is employed in the assessment, planning and execution of our Leadership in Health and Safety program within our offshore business unit in order to maximize the positive effects of cultural change.
Since its launch in 2007 Saipem’s Leadership in Health & Safety program became truly embedded in the organisations DNA, within daily actions and decisions, and the unseen mind-set triggering this. We have achieved a unified vision of a single safety culture through continuous engagement with our offshore vessel management teams & supervisory personnel. We have developed these key roles to be true safety leaders and to further disseminate our safety culture to the people within their sphere of influence.
Our cultural safety training programme is tailored to accurately meet the demanding needs of the population and collaborative training events are undertaken in order to cross pollinate concepts and ideas and the release of multiple ‘phases’ ensures the change process is nurtured and remains omnipresent.
Staggering improvements are evident in terms of organisational safety performance, a very definite year-on-year accident frequency reduction totalling over 50% since the LiHS process was launched, whilst proactive safety observations increased by 70%. Organisational locations where the program implementation was poorly communicated (mainly due to local commitment), sees these positive results lagging. A strong correlation exists between sharp increases in proactive safety observation, with launching of new phases. Reporting gradually decreases over several months, and again spikes with in line with new phase releases. The change process is still ongoing, and constant feeding is critical to ensure high levels of visibility is maintained.
In order to solve sand shale sequences tie mystery, four sequences were proposed for Late Messinian, Abu Madi Formation, which is a multi story fluvial channel system recorded and represented completely in the off shore area with maximum thickness about 320 m. Relative energy, accommodation space, sediment supply, reservoir quality and thickness are decreasing with time starting from sequence one to four, from bottom to top respectively. Each sequence containing three system tracks with a definite sand distribution trend, and subdivided into 13 layers with 10 zones and 9 tested reservoirs.
Early Messenian, Qawasim Formation complex channel system composed of two sequences underlying Abu Madi channel with 500 m average thickness. Upper sequence (sequence two) is occasionally eroded, it can be subdivided into 6 layers with 5 zones and 4 tested reservoirs. Lower sequence (sequence one) which is preserved but not completely penetrated in all studied wells is characterized by an average thickness about 240m and divided into 5 tested reservoirs in the relatively high structure block in onshore area.
Sequences Three and Four in Abu Madi Formation and sequences One and Two in Qawasim Formation can be easily discriminated by the different tools and became the main goal in the exploration strategy in the area. Accordingly, three successive exploratories and six development wells were drilled to explore and exploit these sequences and resulted in high daily production rate about 70 Mscft per well achieved.
The exploration activity in the study area about 4550 Km2 focused on onshore Messinian incised valleys as exploratory successful play after the great Abu Madi field (1976). The offshore discoveries, (Baltim East and Baltim North, 1970s and 1980s) were discovered on the extension of this play with a lot of uncertainties about where exactly is the play borders start and end. NW direction is the main orientation trend for reservoir but who go deeper in detail facing with question not easy to solve especially when leakage of data can judge clearly. Some fields as Abu Madi, Baltim East and Baltim North have original gas/water contact for each zone while El-qaraa field show partial sealing and degree of fault transmissibility with production. On other hand, Nidoco field shows multi gas/water contact, production index and cumulative production show a lot of variance comparing with surrounding fields.
Nile Delta area represents one of the historical mature hydrocarbon provinces in Egypt; since 1970 many discoveries were made in Miocene sequences. The most prolific hydrocarbon play in Nile Delta Central sub-basin is represent by Abu Madi reservoir, which was limited at the sedimentary infilling of a fluvial paleovalley, so-called “Abu Madi paleovalley”. From wells and seismic reconstruction, this valley is developed approximately from south to north for about more than 130 km length and around 5 km width with a 300 meter thickness of stacked fluvio-deltaic sandstones and shale’s.
Due to Abu Madi reservoir production decline, other alternative reservoirs had proposed to explore in the Abu Madi West block. Noroos discovery was one of the proposals, which drilled in July 2015 in Miocene section outside of Abu Madi paleovalley and encountered a 60 meters thick gas bearing sandstone interval of Messianian age with excellent petrophysical properties.
Abu Madi West block was covered with 3D–OBC seismic survey, acquired in 2008 where Noroos discovery was close to the border of this survey. The great results of Noroos discovery were very encouraging to explore more traps in the area but the decision was difficult due to the poor quality of seismic data at borders. Complete seismic inversion study with applying both low frequency and rock physics models was performed to overcome this problem and resulted generation of new prospects with high possibility of success.
In December 2015, Petrobel drilled Noroos East prospect depending on the seismic inversion study, where an important gas discovery has been achieved with a thick gas bearing sandstone interval of Messinian age and excellent petrophysical properties. These discoveries open the gate for the future exploration in this area.
Tempa Rossa is an oil field within Gorgoglione Concession in Basilicata region, Italy, discovered in 1989. Lying more than 4,000 meters beneath the surface, the field is planned to be produced with height wells. One of six existing well has a total depth around 7145mMD, and another well has a horizontal drain around 600m.
Dual Boosting ESP system is the selected solution to deliver 10 000 blpd per well as production target rate. The ESP and completion string were designed considering the limited size of production casing, the high stresses (tubing movement, tension, weight, pressure) and the corrosive environment from the oil characteristics. According to the casing size, two completion designs were created to deploy the dual boost system (type A for 9-5/8” production casing and type B for 7-5/8” casing).
The ESPs can be operated as single, back-up system, or as dual boost system. For the first production years, the ESP will be used in back up mode, thanks to high reservoir pressure, and then subsequently with declining reservoir pressure, the dual boost system will be operated to maintain the required flow.
A Work-Over campaign started in March 2016 with the objective to equip the six existing wells with new upper Dual ESP completion in anticipation of the first oil. Under abstract submission’s date, four of the six Tempa Rossa wells have been equipped with Dual ESP completion: three type A and one type B. Significant improvements in running performances have already been observed thanks to the dedicated operation follow-up.
A post ESP installation data monitoring has been put in place, thru a dashboard, to allow the detection of potential early failure of the Dual ESP system during the idle period until production start-up. Operation follow-up and data monitoring are key factors to minimize the probability of ESP failure prior to the first oil. Mitigation measures for ESP preservation during long period play a key role to accomplish first oil and planned ramp-up in due time.
Throughout the world, there are lots of local projects containing large amounts of freely available vintage seismic data. Differently from modern survey techniques, in which data are collected, processed and stored digitally, these vintage data are currently available only as scanned paper sections. Such a large amount of data can be very useful not only for scientific purpose, but also for the oil industry when other kind of data are not available. However, in the actual digitized form, vintage data do not show their full potential: in most cases, they represent only stacked seismic sections, with some additional noise derived from the vectorization process, and therefore they show a poor final quality. The enhancement of scanned vintage seismic data is presented as workflow, that involves a digitalization process and a processing path in a Seismic Un*x environment. The digitalization process is an essential procedure, because it converts the scanned section in a readable seismic format, the seismic standard SEG-Y, through a series of steps that implies image enhancement and rectification and a georeferencing procedure to assign the shotpoint coordinates. The processing sequence, instead, is the core of the quality enhancement procedure, with well-defined steps that remove the noise related to the digitalization process through filtering and allow to efficiently improve the seismic data by applying a post-stack migration. Furthermore, this is achieved employing only open source and/or freely available software.
A real data example is presented, using marine seismic lines coupled with well data from the ViDEPI project of Italian Geological Society (SGI) in collaboration with Italian Ministry of Economic Development and Assomineraria (Italian petroleum and mining industry association).
The first seismic experiment was performed in the early 1920s, when a team of geologists and physicists recorded seismic waves that had travelled through earth, making use of a dynamite charge as source and a seismograph as a recorder; but was only during the 1930s that reflection seismic was worldwide accepted as a proven method for hydrocarbon exploration.
The number of existing offshore platforms nearing the end of their designed life is increasing but the fields beneath them still contain viable reserves.
With low energy prices this creates pressures on platform operators and designers of new units. While operators often want to continue exploiting platforms beyond their 20-25-year designed lifecycle instead of investing in a new platform, the life extension of existing platform shall be carried out provided the benefits are still higher compared to the maintenance cost.
The challenge is to continue to use, in safe conditions, offshore platforms that have reached the end of their design lifetime and, on the other side, to ensure that to extend the service is affordable.
Safety is identified by minimum target probability of failure: the existing structure is fit-for-purpose when the risk of structural failure leading to unacceptable consequences is adequately low. The required safety target can be then related to the actual system capacity of the platform, measured by the residual strength reserve of the whole jacket evaluated by, e.g., a pushover analysis, and then introduced in a system reliability assessment capable to eventually determine the actual residual life of the structure and maximum return period of the extreme environmental loading that the platform is still capable to withstand.
The issue is therefore to set actual reference value for the safety target, considering that no relevant information is specifically provided in reference rules and international standards (such as ISO 19902) even if implicit in the prescribed safety factors: to this aim a number of existing platforms showing no critical structural components, and consequently certified as compliant with the rules requirements, has been set as a sample for their system reliability evaluation and following definition of actual structural safety target.
The issue of BOP reliability has long been discussed and despite important advances it continues to generate concerns among offshore safety regulators. As for any safety barrier, it is difficult to know its true operational status during process operation. The idea of devising means and methods to somehow monitor the condition of the BOP in real-time has been in on the agenda of operators, contractors and regulators for quite some time. In this paper, we introduce the main functions of a real-time decision support tool related to the subsea BOP retrieval decision during drilling. The main goal of this new tool is to contribute to better-informed decision-making regarding operational safety and reliability of BOPs, while its ultimate purpose is to reduce BOP downtime thus reducing drilling costs while maintaining its safety margin. The Tool incorporates both qualitative and quantitative methods to help guide the operator decision-making after detection of a BOP component or subsystem failure during drilling. Entirely new in this Tool is the use of quantitative probabilistic criteria, which makes it a fully quantitative risk-informed decision support system. The computational engine is based on an advanced time-dependent reliability analysis of each BOP safety function before (normal condition) and after one or more detected component or subsystem failures. Results for the case of a real BOP operating in the North Sea are presented and discussed in this paper.
Together with the downhole safety valve (DHSV), the Blowout Preventer (BOP) is considered to be one of the most critical of the safety systems involved in offshore oil exploration and production operations. Both such devices are active emergency flow blocking ones, but the much higher complexity of the BOP puts it in a special place not only in comparison with the DHSV but amongst the entire set of offshore safety devices. The recent Montara and Macondo (Refs. 1 and 2) accidents have made it entirely visible to the whole world the huge consequences that can result when the BOP fails to perform its assigned safety functions. In addition, recent studies (Refs. 3 and 4) have shown that BOP unreliability is still responsible for 40-50% of drilling downtime, representing a cause of major losses to drilling contractors and oil operators.
The objective of this paper is to describe the first application of three unique chemical tracer technologies in the optimization process of a field development in the Black Sea offshore Romania. These technologies helped in the understanding of fluid flow, fracture effectiveness, and completion design. The paper describes the methodology employed and the results obtained from the combined application of water tracers, oil tracers, and gas tracers in one multistage hydraulically fractured well. Additionally, the tracer design, operational logistics, operational lessons learned, results interpretation, and application of the results in order to improve subsequent completions will also be discussed. Clear correlations were seen between the results of all three tracers, which were in turn compared to production and treatment data, further confirming the value of diagnostic technology. The importance of adequate sampling and offshore operational limitations were identified and resolved. Results from a planned, but due to tracer results, not executed water shutoff of high watercut zones are presented. The results were applied to future completion designs and decision-making processes. This case study is an inside look at the first-ever combined application of oil, water, and gas tracers in an offshore hydraulically fractured well development in Europe. It will discuss how the results from using all three chemical tracer technologies, coupled with additional data sets while applying a synergistic interaction between teams, can be highly leveraged to understand current completions designs and optimize future developments.
The applications of tracers can be tied to most disciplines in the oilfield; from drilling to secondary and tertiary recovery. The focus of this paper is in the application of chemical tracers to completion diagnostics and optimization, and in particular, to multistage fracturing operations offshore.
In the multistage fracturing application of tracer technology, there are mainly three sub-categories of chemical tracers: tracers for the gas phase of hydrocarbons, the liquid phases of hydrocarbons, and tracers for the water-based completion fluids. The presented project utilized all three tracer types at the same time.
A huge amount of data is recorded during well operations, ranging from rig sensors to lithological information, drilling reports, and equipment records.
Usually the use of these data, particularly those acquired through rig sensors, is limited to control in real time drilling operations. However, all these records are highly valuable for future wells engineering and planning. This paper describes how the combination of these data sets increases their value and creates practical analyses for well problems investigation, performance enhancement, and ultimately supports cost reduction by anticipating and reducing risks.
The use of “big data” solutions creates significant analytics combining multiple data types (sensors and reports) both on single well and group of offset wells. Particularly the interpretation of rig sensor data through the automatic recognition of operating sequence, when put together with other data sources, including traditional reports (DDR, DMR, DGR, etc.), provides a much higher granularity than traditional reporting.
Every operation is accurately measured through objective and detailed KPIs (ROP, tripping speed, weight to weight, connection time, etc.). Technical and performance issues are easily evaluated allowing a better understanding of their root causes, anticipating and avoiding the occurrence of these problems in the next wells and measuring activities and operations potential improvement.
As a further output, it supports future well planning by comparing equipment performance or operational sequences with other wells. It provides a full set of benchmark statistics on the main drilling indicators available and directs the selection of the optimal/best solution for the next wells.
A tangible economic benefit of this approach, measured on a real application, can be expressed in the range of 5% to 8% of overall well expenditure.
Furthermore, this innovative use of rig sensor data is supporting contractual strategy definition (impartial evaluation of the performance), operations monitoring (addressing drilling parameters giving the best performance) and training (providing a rich knowledge base for well engineers).
Reserve - estimation statistics show the significance of oil carbonate reserves. Water injection is deemed to be the most successful and widespread secondary recovery method.
The LoSal (low salinity) is a well-established and proved technique for water flooding applied in sandstone rocks to enhance the recovery efficiency for such reservoirs; this method tailors the water salinity degree to extract the highest amount of STOIIP. On the other hand, a few lab experiments subjected to carbonate rocks whether dolomite or limestone.
The research deals with carbonate rocks where – in most real case histories- water flooding fails due to many reasons; however the most common reason is fractures existence in the carbonate rocks.
The research applied water injection for eight carbonate (limestone) core samples extracted from an Egyptian offshore oil field near Gulf of Suez.
Water salinity was tuned three times; three different water salinity to investigate the effect of different water salinities on (1) Residual oil saturation, (2) Recovery Efficiency and (3) relative permeability curves.
Results showed for majority of core samples a decrease in residual oil saturation (Sor) with decreasing water salinity and increase in recovery efficiency (Er).
Results showed from relative permeability curves that mostly enhancement was due to wettability modification or alteration as shown.
Also, results show that there is no clear relationship between applied differential pressure or absolute permeability and residual oil saturation and recovery efficiency. However, low pressure differential (1.5 psi) is enough to afford adequate injection rates of water into the core samples. The results obtained are analyzed through relative permeability curves.
That is achieved through:
Water flooding- as a mean of secondary recovery method for pressure maintenance- dates backs up early as 1865, the use of water flooding as a recovery method did not come into widespread acceptance and use until the early 1950's . In the west Texas, there was a significant expansion of the oil industry in the 1950's with the discovery of a number of very large fields such as Wasson, Slaughter, Levelled, North and South Cowden, Means and Seminole.