|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
ARG-1 exploration sour and high CO2 gas well was drilled vertically in South Sumatra, Indonesia, with a total depth (TD) of around 5000 ft-MD. The operation has been facing many challenges in drilling and completion phase; one of them is the occurrence of massive fluid losses in fractured limestone formation. Pressurized mud cap drilling (PMCD) technique is the possible solution to complete this well without sacrifice drilling fluids in enormous volume and minimize non-productive time (NPT).
PMCD is one of managed pressure drilling (MPD) techniques applied in situations when drilling without return to the surface and with a full annular fluid column which is maintained above the formation. The key of successful PMCD technique is the rotating circulating device (RCD) which is used to close the annulus. Furthermore, sacrificial fluid is injected through drill string and light annular fluid is pumped down from the annulus to maintain borehole fill and prevent annular gas migration.
Limestone formation was drilled with 6 in slim hole which is a contingency plan. In addition, the premature set of 7 in casing was to cover the gas zone which is located above the limestone formation. Total loss circulation occurred when drilling through upper limestone formation. Conventional combat loss techniques i.e. spot loss circulation material, gunk plug, and cement plug were used to cure the loss but none of them give significant result. It took approximately 2 months for combat loss with such common technique. In consequence, PMCD technique was decided to apply in this situation and it only required 4 days to drill until TD and ready to run 4-1/2 in casing. By successfully utilizing the PMCD technique, the company was able drastically to reduce the NPT and reach the TD successfully.
This paper presents a case study of the drilling operation in ARG-1 exploration well that had massive loss circulation while using common combat loss techniques were unable to reach TD. Furthermore, it explains how drilling in PMCD mode allowed operation in ARG-1 to reach the TD after total loss of circulation was experienced and how the completion assembly was run and cemented in PMCD mode.
Pressure and temperature changes during the life of the well (drilling/production) cause some Casing-Casing annulus (CCA) pressure leaks in the annulus between 13 3/8" and 9 5/8" casings, and 13 3/8" and 18 5/8" casings thereby indicating that the well barriers failed to isolate all the zones and subsequently resulting in the migration of the fluid to the surface. Such failures in wellbore isolation prevent us from taking full potential of ourhigh performance wells.
Under most failure conditions, tensile strength of a cement has a greater impact on its failure as compared to the cement's compressive strength. Consequently, increasing tensile strength of a cement is higher priority than increasing its relative compressive strength. This can be achieved by using additives such as latex, polyvinyl alcohol or fibers or simply by increasing cement flexibility. The objective of this paper is to discuss the development, testing and field execution of a new type of cement, Self-Healing Durable Cement to mitigate such failures due to pressure or temperature cycling.
This new cement was developed utilizing novel components that results in a cement with a reduced Young's Modulus. Lower Young's Modulus makes the cement more elastic in order to resist pressure and temperature cycling, absorb applied stresses and prevent cement cracks. The developed Self-Healing Durable Cement also provides an additional benefit of mechanical properties enhancement as the included additive exhibits swelling and sealing capacity when contacted by hydrocarbon fluids. In the event cracks form in the cement, this will be a path for the fluid to trigger the swelling and self-healing mechanism.
The paper includes detailed testing data for thickening time, rheology, free water, settling at different ranges of densities. An additional test was also included to evaluate the durability of the system with time. Mechanical properties testing was performed for cement samples after 10, 20 and 30 days curing at representative targeted field conditions. Single stage triaxial tests were performed on dry cement core plugs to measure static and dynamic properties through ultrasonic and shear velocities. These properties were determined at confining pressures and included the Young's modulus, the Poisson's Ratio, and Peak Strength.
Offset wells cemented with conventional formulations have shown CCA pressure with slight oil flows. The developed Self-Healing Durable Cement was applied for 13 3/8" casing covering oil bearing zones. The deployments were declared successful since negative testing and temperature and pressure cycling did not result in any CCA. Ultimately, good cementing performance is always measured by having zero psi casing/casing annulus pressure.
AlMansoori has implemented Happiness as a key business theme during 2017 as one of the first companies in the private sector in the UAE. The journey of AlMansoori's Happiness implementation is described in this paper with the aim to share the learning to the fellow UAE companies to benefit from. Early results indicate that Happiness got widely embraced in the company with no resistance nor cynicism. The new culture whereby Happiness is an enabler that is on par with health, safety and quality clearly will set-up AlMansoori for a better future both business commercially and as a community of employees.
The horizontal wells are applied to enhance the production rate by increasing the contact area between the wellbore and reservoir, it has been also used to access the highly heterogeneous and unconventional formations. One horizontal well can produce the same amount of 5 vertical wells with a very competitive cost and operational time. Further improvement for the productivity of horizontal well can be achieved by conducting hydraulic fracture operations, especially for low permeable or unconventional formations. This paper shows a new technique to estimate the performance of hydraulically fractured horizontal wells, without a need for using downhole valves or smart completion.
In the literature, few empirical models have been proposed to evaluate the inflow performance of such wells. However, most of these models assume constant pressure drop in the horizontal section, therefore, significant errors were reported from those models. In this work, a reliable model will be presented to predict the well deliverability for hydraulically fractured horizontal well producing from heterogeneous and anisotropic formation. Different artificial intelligence (AI) methods were investigated to evaluate the well performance using a wide range of reservoir/wellbore conditions. The significant of several parameters on the well productivity were investigated including; permeability ratio (kh/kv), number of fracture stages and the length of horizontal section.
The AI model was developed and validated using more than 300 data sets. Artificial neural network (ANN) model is built to determine the production rate with an acceptable error of 8.4%. The model requires the wellbore configurations and reservoir parameters to quantify the flow rate. No numerical approaches or downhole well completions were involved in this ANN model, which reduce the running time by avoiding such complexity. Moreover, a mathematical relation was extracted from the optimized artificial neural network model. In conclusion, this work would afford an effective tool to determine the performance of complex wells, and reduce the differences between the actual production data and the outputs of commercial well performance software.
Hernandez, Susana Amaya (Saudi Arabian Oil Company, Saudi Aramco) | Zhu, Xiangyang (Saudi Arabian Oil Company, Saudi Aramco) | Al-Humaid, Ghassan A. (Saudi Arabian Oil Company, Saudi Aramco) | Al-Attallah, Fahd S. (Saudi Arabian Oil Company, Saudi Aramco) | Al-Humam, Abdulmohsen A. (Saudi Arabian Oil Company, Saudi Aramco)
Deep drilling often requires the use of circulating fluids to facilitate the drilling process, carrying cuttings and rock fragments to the surface. In this practice, microbial contamination and extensive growth of bacteria in the drilling fluids impact drilling operation and reservoir integrity. An onsite and rapid microbial assessment technique is required to provide an early warning of microbial activities in drilling fluids, and manage microbial risks through proper countermeasures.
Bioluminescence method is a rapid testing technique for quantification of living cells based on the measurement of adenosine-5'-triphosphate (ATP) found in the sample. ATP test has been widely used in food and pharmaceutical industries; however, its application in the oil and gas industry has been hindered by many interference substances present in typical oil industry samples. In this study, we have validated an ATP-based bioluminescence test for its linearity and repeatability in various types of samples from drilling rig operations (make-up water, drilling mud, and cement mix fluid). The results from ATP test showed an excellent linear relationship with the microbial numbers in the samples determined by plate count method. The study proved ATP bioluminescence technique as a reliable method for onsite determination of microbial contamination in drilling operations, obtaining results in minutes, rather than days or weeks with traditional methods.
The action levels based on ATP measurements were recommended for drilling engineers to assess microbial risks in drilling fluids. The implementation of this onsite microbial monitoring technique in the field will facilitate real-time detection and immediate mitigation countermeasures for microbial control in drilling fluids, reducing risks such as loss of rheological properties of drilling fluids from biodegradation, H2S production during drilling downtime and deep in the formation, biomass plugging in the formation, and microbial corrosion. This is the first study of the use of ATP-based test to assess microbial contamination in drilling rig operations.
Better understanding of collapse resistance of casing and tubing can unlock significant value in support of Asset Life Extension (ALE), support routine Well Integrity assessments in every day work and save significant cost by omitting costly oversized designs. Many operators still use the traditional API collapse model, which were accurate for tubulars produced 50 years ago but now underestimate collapse resistance and predicts typically 80 – 85% of the real collapse pressure. Adding to the excess dimensioning is the standard procedure of applying a safety factor to this prediction.
Early 2000, a joint API/ISO Work Group 2b (WG2b) under the Steering Committee 5 (SC5) for tubular goods reviewed casing and tubing performance property equations. ISO/TR 10400:2007, equivalent to API TR 5C3, presents the results from the extensive testing, and the Klever and Tamano (K&T) model for collapse prediction was found to be most accurate. Building on the test data from WG2b/SC5 group, a model was made for collapse pressure prediction of tubulars - hereafter referred to as the "Ultimate Limit Strength (ULS) model", where the simulation result is a prediction of tubular failure. Its predictive accuracy is calibrated with a complete set of data from 113 actual collapse tests offered by the Drilling Engineering Association (DEA). The ULS model was used to predict collapse strength of 9 5/8 inch 53.5 ppf, P-110 casing, using parameters with probability density functions (PDF) for the relevant type of pipe, e. g., quenched & tempered (Q&T), hot rotary straightened (HRS). The PDFs for each input parameter were obtained by measurements of the 113 samples and compared with the PDFs obtained by the WG2b/SC5 group. Random value generators in a mathematical spreadsheet allowed for Monte Carlo simulations to output 100 000 collapse strength predictions for the 9 5/8 inch casing in question. With confidence level of 97.5%, the basic strength was 9900 psi using PDFs from the DEA data set. Using ensemble PDFs, the basic strength was 9500 psi – 19.5% greater than API's standard rating of 7950 psi.
Performing casing and tubing design, the industry practice is to develop load cases to identify the design limiting loads for the well. Once identified, the pipe selected needs to be investigated for factors reducing the collapse capacity further, e.g. axial / triaxial loads and wall loss from wear and tear. Axial loading is accounted for in the ULS model through the theories of Klever & Tamano. Aspects briefly discussed and not fully incorporated in the prototype ULS model are the linear derating factors considering imposed ovality, casing wear and experimental formulas derived for increased collapse strength of pipe in compression. These were conservatively approximated by polynomial curve fitting of an alternative formulation of yield collapse strength and tried in a version of the prototype model.
As operators move towards intelligent wells and fields, data management systems need to be adapted to support the transformation. With technology advancements and a growing network of sensors that enable faster and higher frequency data gathering, there is a need to sustainably scale data management systems to the level required to handle higher volumes of data and faster processing response. The most comprehensive systems, however, are those that support efficient decision making.
A Middle Eastern operator embarked on a project to enhance the existing well integrity data management system to add new capabilities and extend the system to other fields in the Arabian Gulf. The updated well integrity management standards were also incorporated to reflect the operator's latest business principles.
The system was further integrated with a geographical information system and well integrity business workflows were developed. The system automatically monitors data and sends notifications on abnormal well conditions. This is being supported by a single repository of all necessary data, historical inspection, pressure trends and well intervention histories.
Through continuous monitoring of operating conditions by the system and automatic task assignment when conditions indicate the rise of well problems, engineers can work more proactively and manage a growing number of assets. Automated monitoring relieves engineers from the efforts previously exerted on manual processes and allows them to focus on the engineering analysis. Having a single repository with historical inspection, safety critical equipment test data, full pressure trends and well intervention histories, provides a wealth of information from which to make informed decisions.
A benefit of having such methodology, from a management viewpoint, is that there is a common approach to well integrity indicators and key performance indicators for all assets. This allows benchmarking from field to field so that a consistent decision making approach can be made and resources of different types properly focused on those places where the challenges and demands are higher. In a period where the industry has gone through some substantial rationalization, the fact that staff can be assigned to different assets through the use of a common system with which they are familiar helps them to quickly understand, analyze and tackle well problems.
This paper examines the application of intelligent software analytics and a robust system to optimize resources and enhance efficiency and performance. By collecting a wider range of data with increased frequency and applying intelligent software analytics, the operator has been able to greatly improve the asset management coverage, thus improving efficiency and performance; satisfying regulatory requirements and achieving production targets.
The increasing need for completions to be capable of withstanding higher treating pressures, combined with complex well geometries and cementing requirements, led to the development of a new 4 1/2-in. completion system that includes liner systems to facilitate isolation objectives, and upper completion systems to create a monobore conduit. This new monobore completion system is rated for 15,–KSI target surface treating pressures.
Traditionally, cementing and isolation objectives have been achieved using liners and liner hangers capable of deploying those liners and also isolating the target zone. To achieve a monobore completion design, an integral tieback receptacle (TBR) is used to tie the liner back to surface. The integral TBRs currently used are either too short to enable the necessary tubing movement stroke, or rated too low to enable the required treating pressure.
A solution was developed integrating a lower polished bore receptacle (PBR) below the liner hanger that is capable of withstanding the pressure requirements, and using a compression-set anchoring system to anchor a seal assembly inside the PBR. To account for tubing movement and help reduce mechanical loading on the tubing and upper completions components, a PBR is placed above the compression-set anchor.
This arrangement enables the liner hanger systems to be isolated from treating pressures, which helps remediate limitations associated with traditional completion systems. Considering that the liner hanger is isolated from tubing treating pressures and that the compression-set anchor does not isolate annular pressure, the TBR on the liner hanger is pressure-balanced, no longer exceeding the pressure limit. Furthermore, tubing-casing annulus (TCA) pressure that is normally applied during stimulation can now support the liner hanger and lower tieback seals.
API Specification 16A defines the requirements for design, testing, and other aspects of drill-through equipment. This includes ram and annular blowout preventers as well as connectors, spools, and adapters. The most recent edition contains changes that will drive a significant amount of rigorous testing to monogram pressure-control equipment going forward. This drill-through equipment will contain many operating system seals that are off-the-shelf but original equipment manufacturers (OEM) must also design custom seal assemblies to contain a flowing wellbore fluid. This requires optimizing the design of the assembly and selecting a compatible elastomer compound. Both steps are critical to meet performance requirements. Once designed, the prototype must undergo a battery of tests to qualify the design to API 16A. Here, formalized test standards divide equipment qualification into performance requirement (PR) levels, either PR1 or PR2. Previous editions of API 16A did not have PR levels.
Laboratory evaluation of elastomer compounds and full-scale component testing may be performed to improve the final product. Lab test results include immersion testing in hydrogen sulfide while product testing at elevated temperature and pressure may be performed in a full-size blowout preventer (BOP). API 16A test standards are used by the industry to monogram the finished product. However, there are limitations in API 16A qualification tests regarding chemical compatibility. Annular and ram BOP packers and seal designs serve as examples of the technological process used to improve performance and extend service life at elevated temperatures and pressures. All testing is tied back to API 16A validation and qualification requirements.
Porter, Mika (Santos Ltd) | Hill, Adam (Santos Ltd) | Vieira, Paco (Weatherford) | Wuest, Chad (Weatherford) | Gregorio, Adrian Paul (Weatherford) | Sardo, Antonio (Weatherford) | Orta, Cesar (Weatherford)
In global underbalanced drilling (UBD) applications, the main contributing factor for downhole fires is often attributed to the use of air as the primary gaseous phase in the reservoir interval. The industry has adopted a general practice to avoid using air in UBD operations in the presence of hydrocarbons. This paper challenges this paradigm by discussing the planning and application of a successful air-foam UBD application in Australia to drill a low-pressure, highly depleted, gas-bearing reservoir. By using air as the primary fluid medium and eliminating the need for membrane-produced nitrogen, the UBD cost was reduced by 25% and reservoir deliverability exceeded the production expectations. This paper discusses the risk mitigations, modeling, and technical justification applied to the challenging project to demonstrate that even when inert gases may be the recommended choice, air can be used safely in some cases to optimize operational efficiency and cost.