Da Silva de Aguiar, Janaina Izabel (Clariant) | Pimentel Porto Mazzeo, Cláudia (Clariant) | Garan, Ron (Clariant) | Punase, Abhishek (Clariant) | Razavi, Syed (Clariant) | Mahmoudkhani, Amir (Clariant)
Recent studies revealed that solids from lab-generated deposits often exhibit compositional differences from those of field deposits, pointing to a more complex fouling process in field operations. The objective of this work was to understand and apply knowledge from field deposit characteristics in order to design and conduct laboratory experiments which yield solid deposits with comparable compositional fingerprints. This approach allows a more objective and reliable product development and recommendation strategy to be adopted for increased success in the field applications. First, oil and deposit samples from an offshore field was characterized. Second, samples of the asphaltenes extracted from oil (AEO) and from the deposit (AED) were characterized based on solubility using an Accelerated Solubility Test (AST). A customized Asphaltene Dynamic Deposition Loop (ADDL) was used in this study to simulate the precipitation and deposition of asphaltenes from the crude oil. Crude oil used in the tests was from the same well where the deposits were collected. ADDL tests were conducted at high temperature and pressure and the composition of the collected deposit from this test was compared with the deposits from the field. At last, Light Scattering Technique (LST) was applied to screen asphaltene inhibitors (AI). Four candidate chemistries were tested on LST. To confirm the efficiency, the high performer was tested on ADDL under dynamic conditions. Deposits collected from the ADDL were characterized and results showed a high degree of similarity to the field deposit. AI1 was evaluated by ADDL and it decreased the deposition in the filters by 60% and 84% at 1000 ppm. This product was selected to be tested in the field and a plant trial is ongoing.
Significant challenges meeting together make Keshen gas field in Kucha foreland basin become unique from geosciences, engineering and economics points of view. These challenges generally link to harsh geography, super deep (>6500m TVD), thick conglomerates (up to 3000m), heterogeneous salt-gypsum laminations (up to 2000m), complex thrust-nappe structure, HTHP, and ultra-tight (matrix permeability < 0.1 md). This paper gives a comprehensive review how the geoengineering Long March assists to successfully develop this field.
A geoengineering team was established to persistently attack on this world-class championship with high-level planning since 2012. Specific research and development of engineering technologies and solutions for data acquisition, drilling, completion, stimulation, testing and production and studies were taking place in parallel. To ensure seamless integration from geosciences and engineering to operation, a five-year geoengineering study was proactively and progressively executed which includes four major steps with respective objectives including 1) understanding fluid distribution and producibility, 2) well production breakthrough and enhancement, 3) optimization of well stimulation and economics, and 4) optimization of field management including surprising sanding problem.
It was recognized three elements and their interactions are critical for production enhancement which are natural fracture (NF) characteristics, production controlling mechanism, and stimulation optimization under super deep, HPHT and extremely high stress conditions. The bottleneck for study was poor seismic quality due to super depth, pre-salt, and complex thrust-nappe structures. Hence the team established comprehensive methodologies with iterative improvements to overcome this bottleneck. Using regional structural geology, outcrops, cores, images and logs as inputs, structure restoration and geomechanics simulators were combined to perform structure restoration, paleo-stresses, and in-situ stresses and eventually 3D NF prediction. To understand production mechanism, analysis of geological and geomechanical factors, NF and stress relationships, single parameter and multiple variables, and transient and production performance were integrated. Big core studies were conducted to understand fracability, NF and hydraulic fracture (HF) interactions, and selections of HF fluids. Based upon, a stimulation optimization approach was implemented which included engineered completion designs, HF modeling and parametric studies, post-frac analysis and optimization, and time effects through high-resolution coupled geomechanics and reservoir simulation. All efforts with evolving knowledge were eventually developed as an interactive expert system to guide systematic stimulation optimization, sanding management and development optimization.
With increasing understanding of reservoir, and implementing innovative solutions, it was enabled to drill wells at optimal locations with less time, simplified well configuration, and less constraints on stimulation and production operations. By 2017, well construction time was reduced by half, natural productivity of wells was doubled, productivity after stimulation was tripled, and overall cost of wells was largely reduced. The success achieved would boost confidence and lighten on development of other challenging fields.
Sour production from offshore and land-based wells causes hydrogen sulfide (H2S) release during downhole and topsides operations. Improper handling of H2S can lead to serious environmental and safety concerns as well as numerous corrosion and compliance issues. Consequently, H2S can add significantly to the total cost of well operations. The application of efficient H2S management technologies can reduce environmental and safety concerns, enable the use of lower-cost materials, and comply with H2S specifications. To remove H2S from mixed production applications, several chemistries are commonly used. The most common are triazines, glyoxal, and metal-based chemistries. Although each can be effective to a certain extent, these technologies have issues with efficiency or they can create serious side issues. The reaction of triazines with H2S in mixed production is highly inefficient and it creates scaling. Glyoxals suffer from poor efficiency, thermal instability, and corrosivity. The metal-based chemistries are the most efficient in mixed production, but in certain application regimes they can create serious solids and emulsion issues. These challenges can increase CAPEX and OPEX as well as lead to significant downtime and lost production. To overcome issues with currently used chemistries in mixed sour production, extensive research was conducted to identify chemistry that would efficiently remove H2S while minimizing negative side effects.
Systematic evaluation was performed for a series of chemistries to compare the scavenging efficiency, with a special emphasis on mixed production systems. Focus was also given on studying the associated side effects like emulsification tendency, scaling tendency, etc. to ensure the chemistry had no/minimal side effects seen by the more conventional chemistries. A high-throughput lab technique is presented that was designed to mimic scavenging tendency in sour mixed production environment. A continuous gas flow testing technique that helped study the reaction kinetics is also described.
Laboratory and pre-field results proved the efficacy of the new non-MEA, non-triazine chemistry in mitigating H2S in upstream, midstream and downstream applications while being especially efficient in mixed production systems. Laboratory testing proved the chemistry to be highly efficient compared to triazine in mixed production systems. Results also indicated the chemistry is non-emulsion forming and has very little scaling tendency. Testing conducted in the field demonstrated that the new chemistry cost-effectively removes H2S and meets the operator specifications.
The novel, non-triazine scavenger technology has significantly better performance than triazine, no emulsion concerns, acceptable HSE, non-corrosive effects, and less downstream concern than MEA triazine or metal-based scavengers. The new and differentiated chemistry reduces CAPEX and OPEX, drives productivity, improves reliability and reduces non-productive time.
Carbonate reservoirs are often comprised of a heterogeneous pore system within a matrix of variably distributed minerals including anhydrite, dolomite, and calcite. When describing carbonate thin sections, it is routine to assign relative abundance levels to each of these components, which are qualitative to semi-quantitative (e.g. point-counting) and vary greatly depending on the petrographer. Over the past few decades, image analysis has gained wide use among petrographers, however, thin section characterization using this technique has been primarily limited to the pore space due to the difficulty associated with optical recognition beyond the blue-dyed epoxy associated with the pores. Here, we present a new method of computerized object-based image segmentation (Quantitative Digital Petrography: QDP) that relies on a predefined rule set to enable rapid, automated thin section quantification with only minor human interaction. We have developed a novel work flow that automatically isolates the sample on a high-resolution (i.e. <1μm/pixel) scanned thin section, segments the image, and assigns those segments to predefined categories – e.g., pores, cement, grains, etc. Using this technique, statistically relevant numbers of thin sections can be rapidly processed and quality controlled, thereby allowing quantitative data such as MICP, wettability, and surveillance data to be integrated with the petrographic observations for a more complete description of the carbonate rock. Our technique can also incorporate multiple layers, such as cross-polarization, Back Scatter Electron (BSE) imaging, and elemental maps, which allow additional information to be easily integrated with results from QDP. The QDP approach is a significant improvement over previous digital image analysis methods because it 1) does not require binarization, 2) eliminates the subjectivity in assessing abundance levels, 3) requires less hands-on time for the petrographer, and 4) provides a much fuller dataset that can be incorporated across an entire well or field to better address common challenges associated with carbonate reservoir characterization, such as understanding pore type and cement abundance, pore connectivity, grain distribution, and reservoir flow characteristics.
3D wide azimuth seismic data plays a vital role in fault interpretation, which has significant importance during exploration and development stages. Interpreting faults in 3D seismic data is one of the most time consuming and challenging process especially when dealing with poor quality seismic data. This paper provides a complete workflow and example of its application from seismic pre-conditioning to fault detection and extraction automatically based on published concepts by Dave Hale. With recent advancement in computer technology, multi-threaded algorithms and data driven methodologies, geoscientists can automatically detect and interpret virtually all discontinuities in seismic data in an efficient manner.
This workflow involves random and coherent noise suppression, seismic likelihood attributes generation to enhance the discontinuities, detect faults and extract them from thinned fault likelihood volume. Unlike other fault tracking methods that use local seismic continuity attributes, such as coherency, this automated method incorporates aspects of Hale's fault-oriented semblance algorithm, which highlights fault planes with unprecedented clarity.
This methodology has been successfully applied on complex faulted reservoirs. It contributes to the extraction of detailed discontinuity information (minor and major) from 3D seismic data. The traditional manual interpretation step that follows the detection of faults was time consuming and error prone. Automated fault interpretation improves the fault tracking accuracy, consistency and significantly reduces fault interpretation time in prospect generation. This workflow will optimize and reduce uncertainty associated with the seismic fault interpretation process.
Subsea Production Systems—Will 2019 Be a Tipping Point? The Golfinho gas field development is among the high-profile projects for which operators agreed to EPC contracts prior to FID. The 286 subsea trees ordered in 2018 was the highest quantity since 2013 and suggests an industry firmly on the right side of a recovery. Increasing orders are a welcome relief for the still-beleaguered subsea supply chain but have yet to translate into meaningful revenue growth. Revenues have remained relatively static over the past 24 months as the growing number of subsea projects hitting the EPCI phase is offset by a transition from high-value pre-2014 backlog to much lower- priced post-downturn contracts.
ABSTRACT Robustness is a system property that reflects its resistance to the initiation of hazardous events and their progression beyond defined limit state thresholds. Under scoped perturbations a robust system should not display disproportionate response or cascading failures. Three levels of robustness are identified: Operational (R1), Survival (R2) and Reserve (R3) that span responses in state space ranging from the safe operating limit (SOL) up to system failure at the ALS limit. Systems engineering methods can be used to define system boundaries then map subsystems and their interactions. HAZIDS can be used to identify critical failure modes for engineering analysis. Risk methods can be used to assess the acceptability of the robustness measure. Robustness is a system property that reflects its resistance to the initiation of hazardous events and their progression beyond defined limit state thresholds. A robust system maintains essential minimum features under scoped perturbations.
The operator experienced an unusual casing failure at a producing SAGD (steam assisted gravity drainage) oil well in summer of 2017. The subject well in the Firebag SAGD field of NE Alberta, Canada had operated successfully for over 11 years. Once the problem was identified, the well was shut in to determine the nature of the failure and options for repair and recovery so it could be returned to operation as soon as possible.
Tasks included identifying and isolating the failure, establishing the cause and nature of the failure, and determining viable repair options. Logging diagnostics to measure/image the failure were performed, which included new ultra-sonic logging imaging technology, high-resolution multi-finger caliper logging, a downhole camera run and conventional eddy flux casing inspection log. Historical log data was also reviewed to assess whether the failure evolved over time, or if the mechanism was acute. Once the nature of the failure was established, the optimal repair method was chosen, planned and carried out.
Sophisticated analysis of multi-finger caliper log data, camera images and new technology in the form of an ultrasonic imaging tool for the casing were utilized and are presented. A discussion of potential root cause mechanisms for thermal wells is provided, including a variety of failure modes that could be ruled out. Confidence in the failure mode specific to this well was increased by considering information acquired from multiple diagnostic tools. The nature of the connection failure determined from this process is outlined, along the rationale behind the repair method selected to remediate the well.
Awan, Kamran (Petroleum Development Oman) | Al Aufi, Mohammed (Petroleum Development Oman) | Al Salti, Hilal (Petroleum Development Oman) | Al Noumani, Hussain (Petroleum Development Oman) | Nabavi, Bijan (Petroleum Development Oman) | Al Ghaithy, Ali (Petroleum Development Oman) | Al Busaidi, Khamis (Petroleum Development Oman) | Al Harrasi, Ali (Petroleum Development Oman) | Al Lamki, Ali (Petroleum Development Oman) | Al Mujaini, Rahima (Petroleum Development Oman) | Al Salhi, Mohammed (Petroleum Development Oman) | Al Nadabi, Seif (Petroleum Development Oman) | Al Abri, Abdulla (Petroleum Development Oman) | Al Zaabi, Yousef (Petroleum Development Oman) | Al Busaidi, Salim (Petroleum Development Oman)
'Sweating the Asset’ is an integrated change management approach for maximizing cheap oil production from existing fields and facilities, without capital expenditure. ‘Sweating the Asset’ utilizes a
The ‘Sweating the Asset’ goal was introduced as an organisational initiative in Q1 2017 with the aim of helping producing assets close their ‘gap to potential’ and operate as closely as possible to technical limit. The approach enables team leaders managing different components of the integrated production system to focus on a common goal and make aligned decisions.
The structured ‘Sweat the Asset’ process integrates components of the company's Lean Management System (LMS), including:
'Sweating the Asset’ has been deployed in 13 production systems within the organisation and currently at different levels of maturity. As an example of goal deployment, an EOR polymer injection facility with suboptimal performance, poor compliance with injection and viscosity requirements had resulted in a severe decline in oil production. In order to safeguard production and close an estimated production gap of 4000 barrels/day, a goal was set to
The plan for 2018 is to ensure that ‘Sweating the Asset’ is fully embedded and sustainable in all assets across the organisation. This may be seen as step change in, and the next level of Wells, Reservoir and Facilities Management (WRFM) maturity. This paper will primarily focus on the Goal Deployment process and strategy.
innovation today is not an option but a necessity, not a general culture but business style. Governments and companies that do not renew or innovate lose competitiveness and Control. They are bound to regress," Sheikh Mohammed National Innovation Week (2015): "Innovation, research, science and technology will form the pillars of a knowledge-based, highly productive and competitive economy, driven by entrepreneurs in a business-friendly environment where public and private sectors form elective partnerships" (Innovation ‘holds the key to our progress, 2018)
Only 11% of the Fortune 500 companies from 1955 still exist today. Root word of ‘innovation’ comes from the Latin ‘Innovare’ and is all about change. ‘Innovation is something new that creates value in the eyes of the consumer’. (‘new combinations’) future growth and performance is maximized’ (The Theory of Innovation, 2018)
ADNOC LNG operates in Loss of production in crisis conditions and where there is an urgent need to find novel solutions and implement them quickly. ADNOC Mission: We harness energy resources in the service of our nation. Vision: Through partnership, innovation and a relentless focus on high performance and efficiency, we maximize the value of energy resources. ("ADNOC - Abu Dhabi National Oil Company," 2018)
Conducting a SWOT analysis in Utility department our strengths consist of the safety within our manufacturing plants, our recruiting information technology are Internally-facing capabilities of the utility Department. Then I look at weaknesses where are our gaps? And we may have gaps in our reporting process. Look for major themes that emerge from the SWOT analysis to feed into the initiatives that you think about pursuing and prioritizing as the highest priority items.
Operational Excellence Theme Operational Excellence stresses the need to continually improve the way we manage our production assets and seeking more cost-effective ways in the whole value chain and reducing environmental impact, particularly in respect to aging assets. Determining core competencies in Utility Department could be things like our ability to innovate, and technology infrastructure. What are we truly great at? What’s first? What’s second? I would argue that their two core competencies are the ability to innovate and technology infrastructure.
Understanding strategic filters in ADNOC LNG Which It’s also going to help you allocate your very limited resources to pursue those initiatives and reach those goals. A common set of criteria that everyone across the organization is going to use to conduct those evaluations. Things like Financial &Economic indicator, HSE improvement, maintain plant production, Plant Availability, improve plant reliability, Plant /Machine performance, Solve obsolescence Aspect and Maintainability. By articulating this set of criteria you’re going to have a common lens to evaluate your initiatives through. Those filters are going to screen out initiatives that aren’t consistent with the stated direction of the organization, and they’re going to be customized based upon the needs of the organization. Understand how much risk they’re going to have you take on. First consider how relevant are your existing capabilities? Looking at your cost structure or the infrastructure. We want to take on some risk, because that’s going to create new opportunities for us, but not so much risk that you’re risking the enterprise.