Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
This article discusses estimation of stresses encountered during drilling that could cause fracturing or formation damage in the near wellbore area. Ballooning is a process that occurs when wells are drilled with equivalent static mud weights close to the leakoff pressure. It occurs because during drilling, the dynamic mud weight exceeds the leakoff pressure, leading to near-wellbore fracturing and seepage loss of small volumes of drilling fluid while the pumps are on. When the pumps are turned off, the pressure drops below the leakoff pressure, and the fluid is returned to the well as the fractures close. This process has been called "breathing" or "ballooning" because it looks like the well is expanding while circulating, and contracting once the pumps are turned off.
Africa (Sub-Sahara) Eni announced an oil discovery in Block 15/06 offshore Angola in the Kalimba exploration prospect that is estimated to contain between 230 and 300 million bbl of light oil in place. The Kalimba-1 NFW well, which led to the discovery, is located approximately 150 km off the coast. The well was drilled in a depth of 458 m and reached a total depth of 1901 m. The data acquired in the well indicate a production capacity in excess of 5,000 B/D. The discovery creates opportunities for exploration in the southern part of Block 15/06, so far considered mainly gas-prone. The joint venture, with stakes held by Eni (operator, 36.8421%), Sonangol (36.8421%), and SSI Fifteen Limited (26.3158%), will work to appraise the updip of the discovery and will begin studies to fast-track its development.
Knowledge of fracture entry pressures or the formation face pressures during Acid Fracturing treatments can help in evaluating the effectiveness of the stimulation treatment in dynamic mode and can also enable and improve real-time decisions during the execution of treatment. In this paper, details of the methods and tools employed to generate formation face pressures in real-time mode with the help of live bottomhole pressure data, is discussed in detail.
The majority of the horizontal wells considered for this study were drilled and completed in the North Sea with permanent bottomhole pressure gauges that enabled constant monitoring of well pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, type of fluid, wellbore description, gauge depth, and wellbore deviation, along with bottomhole pressures to generate formation face pressures just outside the casing at active perforation depth. The tool carries out the calculations as the treatment is being pumped thus providing a dynamic array of several important parameters and can also evaluate the treatment after it has been executed.
Acid fracturing treatments combine the basic principles of hydraulic fracturing and acid reaction kinetics to stimulate acid soluble formations. It is customary to start the treatment with a high viscosity pad to generate a fracture geometry and follow it up with acid to react with the walls of the fracture and etch it differentially. The non-uniform etching action of the acid creates an uneven surface on fracture walls that provides the requisite fracture conductivity which is key to enhancing the well performance. The effectiveness of a treatment schedule can be ascertained by determining and analyzing the pressure behavior during the injection process. Several acid fracture treatments were analyzed using the tool and led to important conclusions related to fracture propagation modes, acid exposure times and effectiveness of given acid types. The results had a direct influence on modification of treatment designs and pump schedules to optimize treatment outcomes.
The knowledge of formation face pressures is critical to the success of hydraulic fracturing treatments, especially in multi-stage and multiple perforation cluster type horizontal well completions. The tool developed in the study helps generate information that predicts pressures at fracture entry in real-time mode.
Risers are considered to be the most critical product in offshore pipeline development taking into account the dynamic loads and sour service conditions they need to withstand. The idea aims at providing a design where the riser is equipped with shock absorbent and thermally insulating material rather than increasing the steel layers around it (conventional method) for making it withstand notorious conditions combined with increased lifetime. Modification in the existing riser design includes reduction in the steel thickness of the riser, addition of an external high carbon steel casing (of larger diameter) around the outermost layer of the riser and accommodation of a filler material between the reduced outermost steel layer and the added outer steel casing. The filler material used is silicone rubber blended with microballoons (hollow glass microspheres usually of diameter 100 nm - 5 mm), which is non-reactive, corrosion resistant, stable to extreme environments, resistant to high pressure, high temperature and shear force. This will bring to you a riser that can withstand very high pressure and temperature. A brief comparison between silicone rubber riser and conventional steel riser is presented in the paper. The economics of the method, and the method itself, is compared to the current riser design. The proposed riser design's cost effectiveness lies in the fact that the layers of the riser being protected by highly resistant silicone-rubber are saved from outer corrosion and other damaging factors, therefore increasing their life and providing reusability. Also, the microballoons used to blend the silicone rubber are produced as waste product in coal fired power stations, hence prove to be economical.
Legislation worldwide is aiming at a good balance between environmental protection and capital expenditure on water treatment systems. There is a clear trend to move from integral discharge parameters like BOD, COD and Dispersed Oil to more focused approaches aiming at Zero Harmful Discharge. The leading management tools are the Environmental Impact Factor from Norway and the Risk Based Approach being developed by OSPAR. Here the Toxic and Nontoxic contents are recognized. This has led to new water treatment technologies using other separation mechanisms than gravity/coalescence to achieve Zero Harmful Discharge. The Macro Porous Polymer Extraction (MPPE) technology uses liquid-liquid extraction to remove dispersed and dissolved toxic constituents. A real life experience on the disastrous effect of unknown toxic content on the bio treatment confirming the Environmental Impact Factor model will be presented. MPPE treats Offshore produced water since 1994 with a 99% removal performance of dissolved and dispersed Oil, BTEX, Poly Cyclic Hydrocarbons (PAHs) and other non-polar toxic constituents. Examples of applications in the North Sea, Europe (TOTAL, Statoil, Shell) and Australia (Woodside PLUTO, Shell FLNG PRELUDE, Inpex ICHTHYS) will be presented. The trend of aiming at Zero Harmful Discharge is supported by future projects in other Geo areas and other markets like shale oil. Finally benchmark studies on current MPPE units show a structural Mercury removal that is being further investigated.
Over the last few years Statoil has performed more than 200 high quality extended leak-off tests. This data has been used for determination of minimum stress and quantification of “formation integrity” parameters wrt well barriers and injection control. However the database includes many other parameters related to the initiation and propagation of a fracture with drilling mud. This represents a unique opportunity to investigate various claims in the industry relating to fracture gradient (FG) and formation integrity. For example, it is possible to compare fracture propagation pressures and determine whether there are any differences between water based and oil based muds. Actual formation breakdown pressure can be compared to theoretical models to determine the statistical validity of such models when used for FG generation. Statistical analysis on fracture propagation pressure permits another type of analysis which can be useful in a risk based approach for the estimation of FG during drilling. The data is also interesting in that it suggests that the subsurface on the Norwegian Continental Shelf (NCS) is not in fact in equilibrium state with frictional strength of faults. For the regions covered by the database, there appears to be other mechanisms that result in higher values of minimum stress than that which would be the case for frictional equilibrium. Finally, and in contrast to many other works, the work shows that NCS sediment packages are primarily characterized by a normal faulting regime.
Statoil has put significant effort in performing high quality stress determination tests during the last decade or so [1-4]. Extended leak-off tests (XLOT) with several cycles are typically performed with drilling mud at casing shoes, and both shut-in and flowback phases are standard. Unlike earlier standard procedures, the flowback stage is performed on a constant choke and the volumes are measured. Interpretation is based on system stiffness approach. The basic procedure calls for a minimum of two cycles [1, 5]:
Gainville, M. (IFP Energies nouvelles) | Sinquin, A. (IFP Energies nouvelles) | Cassar, C. (IFP Energies nouvelles) | Tzotzi, Ch. (Technip) | Parenteau, T. (Technip) | Turner, D. (ExxonMobil Development Company) | Palermo, Th. (Total E&P) | Morgan, J. E. P. (Woodside Energy Ltd.) | Zakarian, E. (Woodside Energy Ltd.)
Technip developed the Electrically Trace Heated Pipe in Pipe (ETH-PiP) technology to overcome some of the challenges associated with deeper and remote offshore oil and gas production. This active heating technology applies power to achieve a production fluid temperature above the hydrate equilibrium or wax appearance temperatures either continuously, during normal production, or intermittently, during shutdown periods. In the unlikely event of hydrate plugging of production lines, active heating can be used for remediation.
The objective of this work was to demonstrate that a long, non-permeable hydrate plug can be dissociated in a safe and controlled manner with the ETH-PiP technology. Technip through a JIP program that started in 2012 at the IFPEN facilities at Lyon with Total E&P, ExxonMobil Development Company and Woodside Energy Ltd. have been investigating hydrate dissociation in heated flow lines and studying the associated risks of local pressure build-up and plug run-away.
A 6 " OD and 18 m long ETH-PiP prototype was manufactured and connected to the Lyre loop. It was equipped with sensors for accurately monitoring the dissociation process. A first experimental campaign was focused on studying different dissociation heating strategies. A second experimental campaign, presented in this paper, studied hydrate plug dissociation under severe conditions: dissociation in a closed volume; dissociation under high differential pressure; dissociation with unbalanced heating; and dissociation in presence of viscous oil.
This paper summarizes the experimental procedures and presents some findings of the second experimental campaign. Massive hydrate plugs of up to 200 kg were formed with high water to hydrate conversion rates. The plugs were characterized under differential pressures of up to 35 bar. The characterizations revealed that pressure communication across hydrate plugs was strongly affected by the presence of free water or oil inside the plug porous structure. Among the dissociation strategies, the dissociation in a closed volume was studied and the pressure management under these conditions was tested.
Common wellbore visualizations are depicted using 2D perspective views. This approach is limited and potentially misleading. Of particular interest to rod-pumping and progressing cavity pumps is the amount of side loading placed on the rod string throughout the wellbore. By illustrating the trajectory of a wellbore in 2D, some nuanced geometries can be easily lost. The familiar "corkscrew" wellbore, for example, is very difficult to depict through simple perspective views. A corkscrew is best visualized at a specific camera angle where the shape is apparent. This best viewing angle is generally not at 90 degrees, where typical 2D perspective views are generated.
Distributed wellbore visualization tools can be applied to both design and analysis of pump installations. Interactive views help to identify points in the well where problems may occur, or have occurred. Strategic placement of downhole equipment such as pump depth relative to perforations and historic fluid levels can be done in a more intuitive way, taking into account a more accurate understanding of the wells geometry.
The use of standards based modern web technologies enables rapid deployment of such a tool to both desktop and mobile devices. Three dimensional graphics acceleration was previously only available in the web browser through plugins and other 3rd party software installations. 3D graphics can now be rendered natively in most modern web browsers without the need for any additional software.
Subsea pipeline electrical heating is a relatively new technology in the Oil & Gas industry that has been developing, quite intensively during the last 15 years. There are two main techniques considered for subsea pipeline electrical heating; the first one, already deployed and in use, is Direct Electrical Heating (DEH) and the second one, currently in the final stage of the technology readiness process, is Electrical Heat Tracing (EHT). Electrical heating of subsea pipelines is expected to be increasingly deployed as an elegant technical solution to optimize the flow assurance management during production pipeline's service life and as a cost saving solution bringing significant reduction of projects overall CAPEX and OPEX. TOTAL has been operating world's unique EHT PiP (Pipe in Pipe) subsea system, installed as an industrial pilot as a part of the Islay (TOTAL UK) project. Following the success of Islay project, TOTAL has studied implementation of the EHT PIP technology for an ongoing deep water brownfield development which consists in the production of new reservoirs as a subsea tie back to an existing FPSO. The "base case" field architecture, a hybrid loop concept, had been selected at initial conceptual study stage. Nevertheless, due to high CAPEX of the "base case" option, TOTAL decided to investigate alternative solutions for the preservation of the subsea production line during shutdown, among which an EHT system appeared as potentially attractive. Therefore, a study was conducted in order to assess if the EHT system is installable, safe, reliable, operable, efficient and environmentally sound throughout its required minimum operating life of twenty (20) years.