pipe

An operator considered using Constant Bottomhole Pressure (CBHP) Managed Pressure Drilling (MPD) in the evaluation phase of a drilling project and decided not to go forward with MPD. While drilling the well, unfortunately, they had a well control event that required an increased mud-weight ultimately resulting in a differentially stuck-pipe condition.

MPD services were exclusively called to help free this differentially stuck pipe/BHA. MPD provided enough flexibility to deliberately reduce the wellbore pressure below pore-pressure and decrease the differential pressure to free the stuck pipe/BHA. Using CBHP variation of MPD resulted in unsticking the pipe as explained in this case history. The detected influx was circulated out with appropriate pump rate (high flow rate) using MPD equipment. The operator drilled forward with the assistance and additional protection of MPD to reach the Targeted Depth (TD) without having further issues in a very narrow drilling window. This successful field operation shows that CBHP MPD can indeed be used to precisely manage the annular pressures, as elaborated in the IADC’s MPD definition, and safely and successfully solve some of the baffling problems of the drilling industry.

The separation of gas from gas-liquid mixture in horizontal wells has become a growing concern in the oil and gas industry. The produced free gas reduces the efficiency of rod pump systems, minimizes oil production and can lead to the failure of the rod pump system due to gas locking phenomena. The impact of two-phase flow on the new horizontal well gas anchor’s performance was investigated experimentally. Each experiment was conducted in a transparent horizontal well flow loop by using water and air as the test fluids. Experiments with and without the new gas anchor in the flow loop cases were studied. The new tool has two mechanisms to prevent gas phase from entering the tubing. The first mechanism is the breakage of the mixture’s wave by the bull plug of the tool. The second mechanism is the separation of small gas bubbles due to the flow through the tortuous path inside the tool. This experimental program quantifies the tool performance regarding the first working mechanism only. The bubble separation via the tortuous path mechanism was not investigated.

The results showed that both with and without tool cases can separate 90 – 100% gas from the mixture, if the inlet of tubing or the tool was fully submerged under liquid phase of the mixture at all time. This condition was achieved under stratified flow where the horizontal part of the well was toe flat or toe-up (0°, +1°, and +2°). The wave breakage mechanism by the bull plug of the tool was confirmed visually. This breakage mechanism established the advantage of using the new gas anchor over no-tool condition.

Krishna Godavari Offshore Block has reservoir temperatures of 420 degF and 12,500 psi of bottom hole pressures, field's HPHT rating is a concern moreover other challenges like the wells are complex in terms of depths, profile, high drift, reservoir with heterogeneity, formation pressure variation. The paper discusses challenges during well planning and their execution with adequate methods to successfully drill and case well with less than 15 % NPT.

In harsh environment of KG Basin, HPHT wells encroach on limits of equipment, leaving little margin for error, resulting in increased risk of rapid gas migration, equipment integrity failure, operating limits of tool. The paper discusses use of RSS-Vortex, 200 degC rated MWD tools, NRDPP, modified casing design, reduction in impact of side forces and high torques, optimized bit design, drill pipe cutting tool, reduction of differential sticking to execute the drilling of well within given time. The case study discusses longest 5 7/8" section drilled in an unconventional casing design under HPHT environment in India.

The paper also discusses the unexpected results and observations obtained during execution of program and the lessons learnt from it. Some drilling methods such as first application of RSS-Vortex in a HPHT environment in India has considerably enhanced the ROP by 100% and also significantly reduced casing wear of production casing by 55 %, use of 200 deg C rated MWD tools has increased the robustness of the drilling BHA resulting in minimizing additional BHA trips due to tool failures. The reservoir section drilling has been optimized to 3 bit trips from 9-13 trips done in offset wells. Use of NRDPP's made drilling of high drifted wells easier and maintenance of surface torque within limits had considerably reduced lost production time and ensured safe operation. The improvisation carried out for bit design and casing design has also saved rig days and cost. The new casing design avoids liner tie back which has resulted saving of 7 days of rig time. The use of effective micronized barite OBM system with controlled measures on HTHP fluid loss has maintained good balance between rheology and fluid loss to prevent differential sticking. The downhole tool failure and stick-slip was reduced by 50% by modulating the Variable frequency drive and choosing adequate bit.

These methods and practices require further optimization to enhance the usability. The established methods discussed have created good drilling practices in HPHT environment for KG field and has reduced the drilling NPT levels. Such a huge transformation in reducing the NPT is very significant in HPHT conditions and many of the practices can be standardized for such operations.

Integrated simulation of reservoirs, wells, and surface facilities is becoming increasingly popular for modeling hydrocarbon production from deep offshore assets. Currently, there exist two common approaches for the integration. The first approach employs separate reservoir and facility simulators; whereas, the second approach combines the two within one reservoir simulation framework. Both approaches have advantages and drawbacks. For example, the first approach can be more accurate for the facility modeling, but overall it suffers from stability issues and long running times. On the other hand, the second approach is always numerically stable and typically provides better runtime performance, but requires additional inputs, e.g., Vertical Lift Performance (VLP) tables. Preparation of these additional inputs can be time consuming and often error-prone. Moreover, the VLP tables used in the second approach are typically constructed with the averaged values of "auxiliary" parameters, such as inlet temperature, water salinity, etc. This averaging can potentially lead to inaccuracies during simulation.

In this paper, we propose a new framework for integrated asset modeling which combines the benefits of the two approaches and hence significantly improves the efficiencies in both workflow construction and simulation accuracy. Our framework is based on the previously presented fully coupled network approach implemented as an in-house extension to a reservoir simulator. Here we extend the approach by introduction of an additional coupling step with a separate pipe flow (network) simulator. However, instead of using the pipe flow simulator to solve the network, it is used only to dynamically generate the VLP tables for the simulator's internal network module. Comparing to the previous fully coupled network approach, our new approach streamlines the simulation workflow by avoiding the necessity of the additional manually created network input. Furthermore this new approach also improves the modeling accuracy by using a generalization of the VLP description (e.g. with temperature as additional dimension) and by avoiding tables extrapolations. In this paper we discuss the new workflow and the new dynamic generalized VLP table construction in details.

Petroleum recovery from oilfield assets increasingly involves wells that are very long in extent and have multiple laterals, multiple tubing strings and multiple control points to prevent breakthrough of unwanted fluids and/or to optimize recovery. Instead of simply controlling rates at the wellhead, downhole devices are now available where apertures and other controlling parameters can be set statically, autonomously, or through surface intervention,. Having various control points in a wellbore that may include numerous flow paths requires a flexible setup and robust algorithms to effectively set all local constraints at various measured depths. This paper describes special constructs called "boundary segments" with a similar set of flow rate and pressure control modes to those available for tubinghead or bottomhole well control. In a multisegment well model whose topology consists of a set of nodes with intrinsic properties such as pressure, global mole fractions, total enthalpy, saturations, etc. and a set of pipes with attributes of length, volume, and a flow rate, these special segments share an existing node but have their own unique pipe together with boundary conditions and an accompanying set of control modes. Boundary segments are highly flexible, elegant, easy to implement, and useful in a variety of cases. This paper will provide reservoir simulation engineers and developers with an understanding of a simple method to calculate primary well control at the surface choke together with multiple downhole constraints from devices and tubing strings.

When developing mathematical models for two- and three-phase flow in long pipelines, the most difficult challenge is to model the frictions, volume fractions and flow regimes accurately. This paper combines 3 different methods when confronting that problem: Dimensional analysis, mechanistic models, and Neural Networks (NN). It is shown that those methods supplement each other in important ways. The dimensional analysis is helpful in upscaling laboratory measurements to full-scale flowlines. In case of 3-phase gas oil water flow, the number of dimensionless groups turn out to be 14. NNs offer a way of correlating that many variables, and that allows the model to account for all dimensionless groups for all types of flow. That overcomes the limitations inherent in the more common practice of focusing on only a few parameters or dimensionless groups for each type of flow regime. But introducing NNs creates a new challenge: We need data to train them.

The last problem is partly dealt with by building on well-established mechanistic models with various factors inserted. It is those factors which are trained by the NNs, not the dependent dimensionless groups themselves. Using mechanistic models rather than a pure "black box" approach leads to much faster training and more accurate results. That has made it possible to train the NNs based on a more moderate and therefore realistic amount of data than would otherwise be required.

The novel approach has been used to develop new software. The FlowRegimeEngine, as it is called, is now incorporated in several steady-state and transient commercially available computer codes. At the end of this presentation results from one of them, FlowlinePro, have been compared to results from the well-established computer code OLGA. The results turned out to be very similar.

The presented dimensional analysis also provides an interesting way of testing commercial software by checking whether results are dimensionally consistent. When doing steady-state simulations with two or more different data sets, chosen so that they form the same independent non-dimensional groups, the resulting dependent dimensionless groups should come out identical. If they do not, it is reason to treat the results with suspicion. When applying the test to FlowlinePro and OLGA, they both passed it nicely for the data-sets chosen here.

When producing hydrocarbons from an oil well, managing erosion of both surface and subsurface components caused by solids in the flow stream is critical to maintaining operations integrity in both land and offshore assets. Although component lifetime prediction has advanced in the past few decades, the prediction's accuracy remains a major oil and gas industry challenge. Current computational models only provide an initial erosion rate which is usually assumed constant until equipment failure. However, observed erosional rates vary as a function of time due to the geometrical changes caused by equipment material loss, which result in variations in solid particle impingement velocity [1] thereby either accelerating or slowing the erosional process. The constant rate simplified erosion model often produces inaccurate results that can lead to unexpected equipment failures or unnecessary equipment upgrades depending on whether the rate accelerates or decelerates. Therefore, developing a transient erosion model to capture the variations of erosional rate is needed for an accurate prediction of equipment lifetime.

This paper presents an implementation of an erosion dynamics model in ANSYS FLUENT, a commercial computational fluid dynamics (CFD) software, to capture the progression of transient erosion. The model has the capability to capture the effects of surfaces receding from erosion at each time interval. By dynamically adjusting these surfaces and recalculating the local flow conditions in the area, this method can predict new erosion rates for each time interval and achieve fully coupled geometry-flow-erosion interactions.

This new erosion dynamics model was validated against experimental data from both literature and physical testing, and was determined to have accurately captured the observed erosion trends over time in terms of location and magnitude. The model was then employed to study two real world applications: 1) in evaluating the erosion risk for a high-rate water injector, it predicted the evolution of damage to a coupler designed to connect different diameter pipes, and 2) in analyzing facility piping systems connected to an unconventional well, it predicted the transient erosion trend from proppant flowback, which allowed for pipe geometry optimization to increase in erosional life expectancy.

Providing competent hydraulic isolation between multiple reservoir sections in horizontal wellbores represents a difficult industry challenge. This paper will discuss some of the practices and tools used for cementing production liners in critical horizontal wells.

Issues with bore hole conditioning, ovality, effective solids removal, and hole collapse are more problematic in horizontal wells. Historically issues occurred while running and cementing highly deviated liners. This was true before and after the cement placement including the premature setting of cement, an inability to run the liner to bottom, difficulties in setting the hanger assembly, pressure in the tubing-casing annulus, and cement channeling. Proper pre-job preparedness including pilot testing of the fluid systems, mud conditioning practices, centralization, cement placement simulations, and well site execution procedures for cementing these liners will be discussed.

The practices to be presented have been executed for horizontal as well as deep vertical gas well applications. Scorecards were developed to measure and assess the processes used. This work explains how this effort as well as the cementing service delivery practices have led to successful jobs. The recommended practices have a positive business impact by minimizing or mitigating operational complications, saving rig time, and reducing the need for remedial work due to poor primary cementing operations.

The paper highlights how the combination of enhanced cementing practices in conjunction with new cementing tools and technologies made important contributions to delivering effective zonal isolation in a highly challenging wellbore environment.

Flow pattern of a multi-phase flow refers to the spatial distribution of the phase along transport conduit when liquid and gas flow simultaneously. The determination of flow patterns is a fundamental problem in two-phase flow analysis, and an accurate model for gas-liquid flow pattern prediction is critical for any multiphase flow characterization as the model is used in many applications in petroleum engineering. The objective of this study is to present a new model based on machine learning techniques and more than 8000 laboratory multi-phase flow tests.

The flow pattern is affected by fluid properties, in-situ flow rates of liquid and gas, and flow conduit geometry and mechanical properties. Laboratory data since 1950s have been collected and more than 8000 data points had been obtained. However, the actual flow conditions are significantly different with any laboratory settings. Therefore, several dimensionless variables are derived to characterize these data points first. Then machine learning techniques were applied on these dimensionless variables to develop the flow pattern prediction models. Applying hydraulic fundamentals and dimensional analysis, we developed dimensionless numbers to reduce number of freedom dimensions. These dimensionless variables are easy to use for upscaling and have physical meanings. We converted the collected data from actual laboratory measurement to the variations of these dimensionless variables. Machine learning techniques on the dimensionless variable significantly improved their predictive accuracy. Currently the best matching on these laboratory data was about 80% using the most recently developed semi-analytical models. Using machine learning techniques, we improved the matching quality to more than 90% on the experimental data.

This paper applies machine learning techniques on flow pattern prediction, which has tremendous practical usages and scientific merits. The developed model is better than current existing semi-analytical or classical correlations in matching the laboratory database.

Phase change, a major factor that restricts the development of gas hydrate, is likely to cause blockage in well completion section (sieve section - wellbore lifting section), thus resulting in the engineering losses. In view of the defects in the previous studies on the confluence mechanism of completion section of gas hydrate pressure drop method mining under openhole completion technology, the flow of gas hydrate in the well completion section was simplified as the Main-Branch pipe confluence model in this paper. Firstly, a physical model was established. On the basis of the energy conservation law and the Peng-Robinson equation, the temperature and pressure coupling model was also derived. Then, the Fluent software was used to simulate the temperature gradient and pressure gradient changes in the Main-Branch model. The gas hydrate phase diagram and PT environment under different velocity were obtained. Finally, the contrast analysis between theoretical model and numerical simulation was carried out and the established model was verified. Through the study of this paper, it is possible to prevent blockage of the well completion section by means of depressurization, which can provide theoretical guidance for the control of pressure drop when gas hydrate is extracted by depressurization. It is important for the exploitation and continuous production of gas hydrate in the later stage.