This paper will discuss the design, qualification, testing and planning of a new intervention conveyance technology used to successfully remediate a failed down hole safety valve (DHSV).
The technology is a high pressure, reinforced, ¾ inch OD hose that is run on standard wireline equipment thereby reducing footprint, manning, cost and job time compared to other intervention methods. The hose has a working pressure of 12,500 psi with a tensile strength of 14,300 lbs. The system is gravity-fed into the well similar to a conventional wireline system and is spooled onto a wireline add-on drum with conventional wireline pressure control equipment (PCE). The difference compared to a standard wireline equipment is a modified add-on drum which includes a swivel for pumping, a purpose built stripper installed above the lubricator, and special inserts for the BOP.
Before mobilisation a series of tests were carried out to qualify the reinforced high pressure hose to ensure it was safe for interventions. Based on successful test results, the coil hose was mobilised and a total of 5 runs were carried out on the first job. These runs included jetting, spotting of chemicals and a caliper survey. The intervention successfully jetted 15% hydrochloric acid (HCl) over the DHSV, and through to surface. The job was an operational success and the DHSV inflow test, post treatment was successful.
The reinforced, high pressure coiled hose is a new conveyance technology that positions itself between wireline and coiled tubing. This technology can access wells on locations where running coiled tubing (CT) operations can be a challenge due to limited crane capacities and/or deck space. While coiled hose is not a replacement for CT due to its limited pumping rates (approx. 50lpm) and gravity feeding, it is suitable for spotting chemicals, N2 lifting and light cleanout operations.
We present an assessment of the impact of low-salinity brine osmosis on oil recovery in liquid-rich shale reservoirs. The paper includes: (1) membrane behavior of shales when contacted by low-salinity brine, (2) numerical model of osmosis mass transport for low-salinity brine, and (3) enhanced oil recovery (EOR) potential of low-salinity osmosis in liquid-rich shale reservoirs. Capillary osmosis causes low-salinity brine to be imbibed into the shale matrix; thus, forcing expulsion of oil from the rock matrix. This oil recovery process is described by a multi-component mass transport mathematical model consisting of advective and molecular transport of water molecules and dissolved ions. In the transport model, the activity-corrected diffusion of the brine solution is used to calculate the volume of brine imbibed into a shale core sample and the resulting expelled oil. We used the mathematical model to match oil recovery from two carefully designed brine-imbibition experiments conducted at Colorado School of Mines. We have concluded that, in oil-wet shale reservoirs, low-salinity brine invasion of the rock matrix is by osmosis rather than capillary force. Thus, osmosis is the only imbibing force that drives the low salinity brine into the reservoir rock matrix. Furthermore, we believe brine osmosis can potentially enhance oil recovery by expelling oil out of the rock matrix and into the micro-and macro-fractures existing in the stimulated reservoir volume.
The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000 m water depth, including subsea production wells more than 25 km away from the production facility. Producing complex fluids within such a challenging environment required demanding thermal performance of the overall subsea asset with both the problematics of steady-state arrival temperature and cooldown. To do so, the transient thermal signature of every subsea component has been evaluated and correlated into a dynamic flow simulation to verify the integrity and therefore, safety of the system.
A unique design of subsea equipment aims to cover a large range of reservoir conditions. In order to tackle both risks of wax deposit during production and hydrates plug during restart, the whole system was designed to have a very low U-value and stringent cooldown requirements. A dedicated focus on having an extremely low U-value for the Pipe-in-Pipe (PiP) system enables to improve the global thermal performance. The accurate thermal performance predictions from computer modelling were firstly validated during the engineering phase with a full scale test. Eventually an in-situ thermal test was performed a few days before the first-oil to assess the as-built performance of the full subsea network. A well prepared procedure allowed to characterize precisely the subsea system U-value in addition to evaluate the cooldown time of critical components, after installation. The error band was properly assessed to take into account the difficulties of performing such remote measurements from an FPSO.
The different elements of the qualification procedure were successful, validating the demanding thermal requirement of the subsea system. The validation of the thermal performance of the flowline was fully achieved. Detailed analysis of the test results was performed in order to define precisely the U-value in operations. The as-built performance verification, including all elements of the complex subsea network, allowed to validate the optimized operating envelopes of the production system.
A detailed qualification process was conducted in order to fulfill one of the most challenging thermal requirements for a subsea development. Thanks to the precise prediction of the flowline insulation performance, the different reservoir conditions are safely handled. The operating envelope of the production system is finally optimized with the confidence from as-built performances confirmation.
In a deepwater environment, production fluid conditions have to satisfy complex requirements to flow smoothly to the production facilities on the FPSO. Flow assurance specialists work at turning these constraints into operating guidelines. This allows to close the gap between reservoir conditions, optimized design of the subsea network, topsides processing capabilities and operability requirements.
In the context of Kaombo, offshore Angola (Block 32), the wide range of reservoir conditions and fluids plus the extreme specificities of the subsea network called for an innovative approach with the following objectives: Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls Allow a design robust enough to tackle geosciences uncertainties Optimize subsea design margins
Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system
Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls
Allow a design robust enough to tackle geosciences uncertainties
Optimize subsea design margins
This new approach, the "Visual Operating Envelopes", aims at explicitly and visually defining the operating limitations of the subsea production loops in a multi-parameters environment: A multi-dimensions map, function of the six main parameters (basically liquid and gas-lift flowrates, water and gas contents, reservoirs pressure and temperature) influencing multiphase flow into pipeline is hence created to evaluate the six main operating constraints (thermal and hydraulic turndown rates, wells eruptivity, maximum flowrates) for the full range of Kaombo fields.
This "operating envelope" tool can then define the minimum and maximum recommended flowrates for different operating conditions based on the following safe criteria: Arrival temperature above the Wax Appearance Temperature No hydrates risk during preservation No severe slugging effect Production below the flowline design flowrate Velocity below the erosional velocity
Arrival temperature above the Wax Appearance Temperature
No hydrates risk during preservation
No severe slugging effect
Production below the flowline design flowrate
Velocity below the erosional velocity
In addition, the optimized gas lift flowrate is directly accessible, and the pressure available at every wellhead is compared to the backpressure associated to the operating point to assess the eruptivity of the wells.
By having previously defined an overall operating envelope, it is extremely easy to evaluate quickly the impact of new operating conditions (due to degraded operating conditions, changes in reservoir parameters, modifications in the drilling and wells startup sequence), which makes this new approach very powerful and versatile. It also contributes to the definition of the production forecast during operation phase integrating reservoir depletion and available gas lift rate.
Instead of relying on specific simulations for a limited number of cases, this innovative method defines a new approach where operating parameters are evaluated from the start, and boundaries are clearly identified, thus allowing to build a sound production profile for an extensive range of operating conditions. By doing so, system knowledge is improved, bottleneck conditions are anticipated, operators, flow assurance and geoscience teams are able to tightly collaborate and take smarter decisions together, resulting in more production. Eventually the method applied to a multiphase pipeline is actually transposable to every problem involving multi-dimensional inputs with combined constraints.
The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000m water depth, including subsea production wells more than 25km away from the production facility.
During the project phase, measures have been taken in order to standardize the subsea design overall including the thermal requirements. By necessity the insulation design of the subsea component is driven by the most stringent part of the development which is then applied throughout the complete system on Kaombo. This inevitably infers that certain parts of the system operate with a built-in margin regarding thermal performance. With an overall objective to optimize the OPEX the use of this margin on some assets generates added-value in the operational phase by reducing production shortfalls through reducing the number of preservations undertaken during life of field.
In order to improve the overall preservation sequence, crude abilities to delay hydrates formation and/or to transport hydrates have been studied on the coldest fields. It was found that studied crudes present interesting properties to delay hydrates formation. These tests have been performed with crude samples in lab conditions in order to assess the temperature and pressure when hydrates start to form. The results indicate that it is possible to extend the waiting period (i.e. time before launching preservation) well inside the hydrate thermodynamic zone and operating "safety" zones have been defined depending of the actual temperature and pressure.
An optimized preservation sequence postponing the decision point to restart or preserve was finally implemented thanks to:
An accurate knowledge of the full system thermal performance especially including the weak links The study of crude properties for the most penalizing fields vs. hydrates plug risk
An accurate knowledge of the full system thermal performance especially including the weak links
The study of crude properties for the most penalizing fields vs. hydrates plug risk
The methodology implemented is today already field proven and application of the extended waiting period was performed allowing reduction of shortfalls and smooth restart. A significant impact is expected for the full life of the field.
Offshore wells drilled in the central and northern North Sea have historically suffered from borehole-instability problems when intersecting the Upper/Lower Lark and Horda Shale formations using either water-based mud (WBM) or oil-based mud (OBM). A wellbore-stability investigation was performed that focused primarily on improving shale/fluid compatibility. It was augmented by a look-back analysis of historical drilling operations to help identify practical solutions to the borehole-instability problems.
An experimental rock-mechanics and shale/fluid-compatibility investigation was performed featuring X-ray-diffraction (XRD) and cation-exchange-capacity (CEC) characterizations, shale accretion, cuttings dispersion, mud-pressure transmission, and a new type of borehole-collapse test for 10 different mud systems [WBM, OBM, and high-performance WBM (HP-WBM)]. The results of this investigation were then combined with the results of a well look-back study. The integrated study clearly identified the root cause(s) of historical well problems and highlighted practical solutions that were subsequently implemented in the field.
The borehole-instability problems in the Lark and Horda Shales have a characteristic time dependency, with wellbore cavings occurring after 3 to 5 days of openhole time. The problems were not related to mud-weight selection but were instead caused by mud-pressure invasion into the shales, which destabilizes them over time. An experimental testing program revealed that this effect occurs in both WBM and OBM to an equal extent, which explains why nonoptimal field performance has historically been obtained with both types of mud systems. New HP-WBM formulations were identified that improve upon the mud-pressure invasion and borehole-collapse behavior of conventional OBM and WBM systems, yielding extended openhole time that allows the hole sections in the Lark and Horda Shales to be drilled, cased, and cemented without triggering large-scale instability. Look-back analysis also indicated that secondary causes of wellbore instability, such as barite sag, backreaming, and associated drillstring vibrations, should be minimized for optimal drilling performance. A new HP-WBM system, together with improved operational guidelines, was successfully implemented in the field, and the results are reported here.
Full waveform inversion (FWI) of onshore targets is very challenging due to the complex free-surface-related effects and 3D geometry representation. In such areas, the seismic wavefield is dominated by highly energetic and dispersive surface waves, converted waves and back-scattering energy. We use a timedomain spectral-element-based approach for elastic wavefield simulation in foothill areas. The challenges of the elastic multiparameter FWI in complex land areas are highlighted through the inversion of the pseudo-2D dip-line survey of the SEAM Phase II Foothill dataset. As the data is dominated by surface waves, it is mainly sensitive to the S-wave velocity. We then propose a two-steps data-windowing hierarchy to simultaneously invert for P- and S-wave speeds, focusing on early body waves before considering the whole data. By doing so, we aim at exploiting the maximum amount of information in the observed data and getting a reliable model parameters estimation, both in the near-surface and in deeper part. The model constraint that we introduce on the ratio of compressional and shear velocities also plays an important role to mitigate the ill-posedness of the inversion process.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: 207C (Anaheim Convention Center)
Presentation Type: Oral
Deviated wells pose an inherent risk to down-hole tubulars via increased bending and contact loads. Deviation is a "necessary evil" when it comes to directional wells as periodic well path corrections are often needed to stay on course for a planned trajectory. These intrinsic deviations generate bends and kinks in the wellbore, effectively reducing the "pass through" diameter of a given well section and making it more difficult to move a tool string through the well. Understanding this tortuosity limitation is instrumental in helping engineers to better place completion components for mitigating risks associated with high stress environments; such as fatigue, premature wear, and difficulty running-in-hole.
A new analysis software has been developed that analyzes the geometry of the wellbore and its effect on the mechanical loading of down-hole tools by utilizing a combination of gyro-based high-density surveys and ID measurements from multi-finger caliper logs. Using a specified tool length, (i.e. the length of a pump) this methodology allows for a determination of an effective tool OD or length that can be run so as to avoid any bending in the tool. This approach also allows for a quick comparison of multiple tool assembly lengths in order to aid in the tool selection and decision process. The results are supported with enhanced 3D visualizations, which help to effectively describe the tortuosity present in a wellbore and estimate the allowable pass-through ID ("Effective ID") for a specified tool length.
Some real-world applications of this technology are presented in detail. The OD and lengths of components placed in the wellbore can now be considered; determining if completion tools will experience bending while being run down-hole, if a holdup while running-in-hole is probable, or if operating at a certain setting depth is likely to result in premature failure. These results may then be used to optimize the completion string, artificial lift setting depth, or allowable tubular size for subsequent casing or tubing strings. Similarly, non productive time (NPT) associated with problems running other completion devices (perforation guns, plugs/packers, tubing, liners, etc.) in the well can be avoided by utilizing this analysis.
Now, completion and production engineers can have a better understanding of the tortuosity in the wellbore and its effects on the production or completion equipment to be run in the wellbore. This study provides insight into the practical application and utility of high-density surveying, caliper-logging, and estimating tortuosity while considering tool lengths and ODs. Comparing the results obtained with both standard measurement while drilling (MWD) surveys and short interval surveys, it is shown that standard dog-leg severity (DLS) measurements lack the required resolution to properly model the effective diameter of the wellbore. Utilizing the new approach has proven to be more valuable for artificial lift placement optimization, identifying wellbore access issues, and quantifying wellbore tortuosity.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Jian, Guoqing (Rice University) | Ma, Kun (Total E&P) | Mateen, Khalid (Total E&P) | Ren, Guangwei (Total E&P) | Bourdarot, Gilles (Total E&P) | Morel, Danielle (Total E&P) | Bourrel, Maurice (Total E&P) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George (Rice University)
Pengfei Dong, Maura Puerto, and Guoqing Jian, Rice University; Kun Ma, Khalid Mateen, Guangwei Ren, Gilles Bourdarot, Danielle Morel, and Maurice Bourrel, Total E&P; and Sibani Lisa Biswal and George Hirasaki, Rice University Summary Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding. A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. N/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs. Introduction Carbonate reservoirs are thought to hold approximately 60% of crude oil and 40% of natural-gas reserves in the world (Akbar et al. 2000). However, oil recovery in carbonate reservoirs poses great challenges to the petroleum industry. These fracture networks provide a bypass, usually called a thief zone, for the fluids injected into the reservoirs. In addition, approximately 80 to 90% of carbonate reservoirs are intermediate-wet or oil-wet (Treiber and Owens 1972; Chilingar and Yen 1983), resulting in an unfavorable condition for spontaneous imbibition by capillary forces (Hirasaki and Zhang 2004). These characteristics of carbonate reservoirs cause low sweep and displacement efficiency and, hence, low oil-recovery rates.
Cool Down Testing (CDT) used to be an integral part of project execution justified in order to verify the thermal performance of an insulated subsea production system. To combat cost and schedule risk a joint venture set out to qualify Computational Fluid Dynamics (CFD) methods to fully predict the thermal performance of any insulated subsea component and/or system without the need for future CDTs. This paper outlines the results from that work where CDT data compared to simulation results prove predictability within 1 °C accuracy for the subsea system product range.
Results from simulations and full scale cool down tests on Kaombo Subsea Production System (SPS) reveal the importance of a system approach where interaction between components enables a system including thermal weak links to adhere to some of the most extreme thermal requirements seen in subsea development to date. Utilizing this approach the thermal system can be wisely managed retaining heat where available and allowing for local cold spots which, treated individually, would never meet the thermal requirement. The CFD tool enables the system provider to predictively size the insulation for the whole SPS without the need for future cool down testing. The predictive CFD tool furthermore enables a reduced execution cost and schedule risk by cutting out future cool down testing. This is especially important for small to medium sized brown field developments where cool down test avoidance constitutes considerable savings in the SPS budget. Avoiding late project findings and insulation system over-sizing to combat uncertainties also help to considerably drive down execution cost and risk for insulated subsea production systems.