|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
A wellhead choke controls the surface pressure and production rate from a well. Chokes usually are selected so that fluctuations in the line pressure downstream of the choke have no effect on the production rate. This requires that flow through the choke be at critical flow conditions. Under critical flow conditions, the flow rate is a function of the upstream or tubing pressure only. For this condition to occur, the downstream pressure must be approximately 0.55 or less of the tubing pressure.
Abstract In this paper, an assessment of a streaming dataset from all active steam injectors in a mature steamflood field is carried out to understand and identify data trends and patterns which indicate if a steam injector is out-of-design. The dataset utilized in this study comprises real-time data and data in motion available thanks to the newly instrumented asset. However, this high-frequency data, while available, was never analyzed before this study. This work showcases the first study of this kind that utilized high-frequency streaming data from steam injectors. As an exploratory study, it revealed powerful insights and patterns which explained not yet understood behaviors. The methodology employed involved management and analysis of large volumes of data and consideration of the steam distribution system network. The study revealed the root causes of out-of-design and questionable steam quality values, which led to a comprehensive report describing the events, recommendations, and remedial actions for 33 out of 111 active injectors. The business driver for this project relies on solving cases in which the real steam quality is unknown, or the injector is out-of-design, which affects the steam-flood delivery and, consequently, the oil production performance. The novelty of this study relies on the capability of identifying undesired events at very early stages. In similar oilfields under steam-flood operations, steam injectors performance is tested and analyzed every three to six months. Many undesirable events may occur and are ignored in the time window between tests. The study not only led to business value impact due to addressing un-optimized injectors but also started a new program for real-time monitoring. This research demonstrates the value of using high-frequency raw data for steam injectors diagnosis, management, and monitoring.
ABSTRACT Oil and gas well plugging and abandonment (P&A) presents a very significant challenge to oil and gas operators worldwide. Their associated costs are projected to be many billions of dollars in expense, without any financial return on investment. Shale formations creeping into uncemented annular sections behind casing can simplify well abandonments significantly, allowing them to be conducted rigless at significantly reduced complexity and costs. This paper deals with a new experimental technique developed to test shale formations for their ability to form annular pressure barriers, and to quantify important properties associated which such barriers. The technique involves modified thick walled cylinder triaxial testing of cylindrical shale samples with a simulated casing string in the wellbore, leaving an annular gap between the shale and the casing. In-situ stresses, fluid pressures, and temperature are applied to the sample, which will creep into the annular gap in response to the applied loads and the chemical environment of the fluid in the annulus. Strain responses of the shale sample are monitored as the sample deforms by creep, and a modified form of the pressure pulse decay technique is used to (1) probe for the status (open/close) of the annulus and quantify the timing of barrier formation; (2) determine the permeability of the barrier once it forms. At the end of the test, a modified "leak off" test is performed to determine the maximum differential fluid pressure that the newly formed barrier can withstand. This new "shale-as-a-barrier" (SAAB) experimental technique and equipment is described in detail and illustrated using several actual shale tests using North Sea shales that form actual shale barriers through creep in the field, thereby simplifying — and lowering the costs of — North Sea well abandonments. The technique is expected to become an important tool to investigate if certain shales will naturally form creep barriers or can be somehow stimulated to form such barriers (e.g. through exposure to pressure and temperature changes and/or changing the chemical fluid environment in the annulus).
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 29413, “Validation of Cost-Effective Design Methods Using Hydrostatic Head for High-Pressure/High-Temperature Applications,” by Parth Pathak and Nicholas Katsounas, OneSubsea, prepared for the 2019 Offshore Technology Conference, Houston, 6–9 May. The paper has not been peer reviewed. Copyright 2019 Offshore Technology Conference. Reproduced by permission. Validation testing of subsea equipment designed for high pressure/high temperature (HP/HT) applications is necessary but can be extremely expensive and infeasible. The complete paper presents a practical approach for validating design-verification analysis for subsea equipment, using a representative pressure valve block to correlate finite-element analysis (FEA) predictions for strain changes with actual measured changes. The design methods use the guidelines in technical report API 17TR8, and load cases per API 17TR12. Introduction Current editions of API standards covered in API Subcommittee 17 (API SC 17) for subsea production equipment are geared toward designing the equipment for its absolute internal working pressures. Also, on the basis of previous regulatory requirements for the offshore industry, until 2014 it was not advised to take advantage of the external seawater hydrostatic head and other external pressures to design certain types of subsea equipment covered under API SC 17. Thus, equipment per its corresponding API standards was designed to have an absolute rated working pressure always greater than the well shut-in tubing pressures. Three API technical reports published in 2014 and regulatory guidelines for the Gulf of Mexico published in 2017–2018 provide design guidelines for depth-adjusting subsea equipment specific to its working seawater depths, and detailed verification and validation guidelines for designing HP/HT equipment—that is, with absolute internal pressure rating exceeding 15,000 psi and temperatures exceeding 350°F. These guidelines can be used to develop subsea equipment rated to working pressures greater than 15,000 psi. The complete paper details the step-by-step methodology of combining the API 17TR12 and API 17TR8 design verification guidelines to depth-adjust typical existing 15,000-psi-rated subsea equipment for HP/HT use. Validation tests for external pressures for entire equipment assemblies can quickly become impractical and infeasible for most of the equipment covered in API SC 17 because of the sizes and complexity of the equipment. The authors believe such testing is not entirely necessary because testing for external pressure of critical and representative components, which are pressure-containing and -controlling, can be sufficient to validate the applicability of the external pressures for the equipment. Furthermore, they contend that for larger components for which hyperbaric chamber testing might not be feasible, comprehensive FEA can be used to validate stresses and deflections as long as the FEA methods and results are appropriately validated. The complete paper presents the various tests that were performed covering typical subsea equipment and are deemed sufficient to validate the verification methods used to depth-adjust using external pressures. The actual tests performed were part of an HP/HT development for the completion and workover riser (CWOR) system for a potential application that required depth-adjusted working pressure higher than 15,000 psi. The work performed was to validate the design and verification of the equipment manufactured by the services provider and cannot be applied to other manufacturers or engineering houses.
Jia, Wenlong (Southwest Petroleum University) | Yang, Fan (Southwest Petroleum University) | Mu, JunCheng (Kongsberg Gigital AS) | Cheng, Tingting (Southwest Petroleum University) | Li, Changjun (Southwest Petroleum University) | Zhang, Qi (Deepwater Engineering & Construction Center CNOOC China Ltd.-Shenzhen Branch)
Abstract Co-existence of gas, water and glycol is commonly in produced fluids of high-pressure gas wells due to formation water production and hydrate inhibitor injection. The interaction between the polar water and glycol molecules can affect the phase behavior and subsequent temperature change during gas flowing through chokes at wellheads. This paper presents an isenthalpic flash method based on the cubic-plus-association equation of state (CPA EOS) to calculate the temperature at the downstream of the choke. In comparison with the traditional isenthalpic flash algorithm, this new method accounts for the self- and cross-association between polar water and glycol molecules, yielding more accurate enthalpy calculation results for fluid containing water and glycol as well as choke temperatures. The proposed model is validated with field test data. Results demonstrate that the average absolute deviations between the measured and calculated temperatures at downstream of chokes based on the proposed method are less than 1.6°C even for vapor-liquid-aqueous three-phase mixtures at pressures up to 100 MPa. Results yield from the proposed method are more accurate than those calculated from the SRK EOS combining with the Peneloux volume shift method and the Huron-Vidal mixing rule.
Summary 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.
A deep insight into tight gas transient flow behavior is important for understanding the production behavior of tight gas reservoirs. In this work, we constructed a two-dimensional model to illustrate one methodology of evaluating effective permeability of fractured flow media. Pulse-decay experiments on one fractured core to study porosity and permeability for both matrix and the fracture, under a series of pore pressure and effective stress. Based on the results, the approach proposed in this study has the advantage over the steady-state method that can capture the character of transient flow if the fracture network penetrates the core. The transient gas propagation in the matrix, fractured cored with the fracture width of 1 μm and 1 cm are in shapes of piston-like, arrow-like, and dumbbell-like, respectively. Though the fracture width is only 1 μm, it reduces the time to reach pressure equilibrium to about one-fourth and the effective permeably ratio is 3.98. Totally 59 pulse-decay experiments were performed on one fractured core. We successfully history matched all the pulse-decay experiments on a fractured core by a commercial simulator with the Global Match Error (GME) less than 0.2%, that the readers can readily adopt this approach. Based on the history matching of upstream and downstream pressure curves, the fracture permeability and porosity are 6 orders’ and 1 order's magnitude higher than the matrix. The matrix permeability is the most sensitive to the pore pressure and effective stress, and no consistent trend is observed for the fracture permeability and porosity as the pore pressure and effective stress change.
Summary The R-ratio is considered a constant, equal to the area of the port (Ap) divided by the bellows effective area. When gas lift valves are tested for both opening and closing pressures, it is possible to calculate the R-ratio. The calculated R-ratio from test data is consistently larger than the manufacturers’ published R-ratios. This paper presents a discussion of the factors affecting the R-ratio and an explanation for the difference between published and tested R-ratios. The R-ratio is not a constant but varies with dome pressure, port-material strength, bellows size, and port size. A method is proposed to calculate or test the true R-ratio. The use of the area of the port (Ap) in the R-ratio is not completely accurate. The area should be the seal area (As) defined by the outer-sealing diameter of the ball (Ds) on the port. It is possible to test valve behavior to determine the seal area, and it is recommended that the tests be conducted in order to use the correct R-ratio when designing gas lift wells. A method to apply the use of the measured R-ratio is also provided.
Abstract Presented in this paper is a model-based approach for performance and health monitoring of a double spool blowout preventer (BOP) pressure regulator. Governing equations of the pressure regulator are derived based on mathematical and functional relationships. The relationships are carried to a simulation environment. Same approach is followed to generate the model of an annular preventer control circuit from the hydraulic power unit to the preventer itself. The nominal performance the regulator during an annular preventer closing event and effects of internal leakages are shown via simulation. Model-based condition and performance monitoring techniques are developed to detect regulator internal leakages and regulator instabilities. The methods are demonstrated over a dataset obtained from a deepwater BOP. The results show that the leakage detection method can differentiate between a leaking and non-leaking regulator within the same BOP, and that regulator instabilities can be detected with the given sensor set and data acquisition capabilities.
Ahmed, Hassaan (Pakistan Petroleum Limited) | Ali, Syed Dost (Pakistan Petroleum Limited) | Ansari, Muhammad Mubashir (Pakistan Petroleum Limited) | Farid, Syed Munib (Pakistan Petroleum Limited) | Khan, Muhammad Wahaj (Pakistan Petroleum Limited) | Shaukat, Athar (Pakistan Petroleum Limited) | Jamil, Aamir (Pakistan Petroleum Limited)
Abstract The case study presents an integrated workflow with the focus on the thermal analysis of the completion string, wellhead and surface network. The research outcome are the temperature profiles under various production scenarios that are used as the justification of the installation of wellhead cooler on an exploratory well of lower Indus basin in Pakistan. The advent of deep well drilling in high temperature and high pressure formations posed serious concerns for drilling, completion and facility design engineers as these are one of the key parameters for material and fluid selection for completion string. The uncertainty in these parameters throughout the operational life of the well may cause an over-designed or underdesigned well completion and production facility. The equation gets further complex if the inherent uncertainty in type and quantity of produced fluids is neglected or underestimated. To overcome these challenges, a workflow considering the downhole completion considerations and wellhead treatment of produced fluid; in consideration of wellhead temperature; is proposed. This paper presents reservoir and completion design considerations of an exploratory well in lower indus basin. Effect of various production scenarios on temperature profile are considered based on the possible drive mechanisms of hydrocarbon production. The analysis includes the development of completion string model for well S-X1 and coupling the same with the hydrocarbon processing facility through surface network. The model is calibrated using history matching of temperature profile using the production data and sensitivity analysis of various parameters was performed. Based on the simulation results, it was observed that the proposed workflow using industry standard commercial software for thermal analysis is a more realistic approach for temperature prediction using production profiles. The proposed workflow will serve as the guidelines for wellhead and surface facility design under various expected production scenarios.