production control

The reservoir management team is often facing a standardization challenge during audit and screening of inactive wells, especially if this task involves multiple mature oil reservoirs or fields. Such a well candidate screening process is normally required to select candidates for revival as well as plug and abandonment (P&A) candidates.

Shut-in wells across different fields may be sharing common issues such as pressure depletion, liquid loading, and high water cut, however, the severity of well-related problems varies from one field to the other. This is in addition to the variation of wellbore mechanical issues such as well-bore integrity, wellbore accessibility, and others. This paper aims to demonstrate a workflow to provide a quantitative ranking of wells. It can be used to standardize an audit process during multi-reservoir or multi-field inactive-well candidate screening study.

The standardization process was addressed by developing a tool that registers the shut-in well ranking upon completing the well potential and risk assessment process. Well level petroleum engineering and production data analysis such as decline curve analysis, nodal analysis and well modeling are performed to estimate the remaining well potential. Subsequently, to enable a comparison across different fields, behind pipe well potential was normalized using multi-field parameters. The audit process followed with well workover risking based on ease of workover intervention including workover options such as water shut off, remedial wellbore integrity work, stimulation and others where it also draws on local knowledge for well risk calculation. The approach presented in this study provides a comprehensive tool for both key performance indicators; remaining well potential and well risk, that are usually required to short-list wells for workovers.

The standardized audit process was demonstrated in a case study where a large number of shut-in wells from multiple mature oil fields were ranked. In this study, the 7 highest ranked wells were recognized as production enhancement candidates and conversely, a number of wells with the lowest ranking were identified for well abandonment. Through this standardized workflow, the well risk assessment was performed efficiently with tools that enable a consistent result across different fields. It helped to accelerate the reservoir management decision-making process in identifying wells with the most impact to increase the success probability during inactive well revival and workover. The workflow and the tool presented in this paper has the potential to be used as analytic tool or template and can be used as a live document that may be adopted to reduce the workload and improve shut-in well management.

Inflow Control Devices (ICDs) have been adopted for commercial steam-assisted gravity drainage (SAGD) production for nearly ten years and yet the function they serve is not well understood, and field data evaluating their performance remains scant. Thus, the purpose of the current study is twofold: Firstly, the study derives a simplified analytical model demonstrating how increasing the dP across ICDs acts to improve conformance along a producing lateral. The resulting equation of the analysis acts as a simple rule of thumb for determining an appropriate pressure drop across ICDs to achieve conformance. Secondly, the study evaluates the performance of ICDs that had been installed in four wells, two of which had ICDs installed prior to circulation and two that adopted ICDs later in their lifecycle. The field data shows that ICDs increase production rates and improve conformance along the lateral. These improvements are achieved by an increased drawdown facilitated by the ICDs. This part of the study highlights how early-life results may differ between ICD bearing wells compared to their conventionally completed (slotted liner) offsets, with the improved conformance and ability to develop more challenging reservoir resulting in different oil production profiles and composite SORs.

Liner failure is one of the key risks in operation of SAGD producers and is often associated with erosion as a result of steam production (Burke, L. et al. 2018). Among various intervention methods, tubing deployed inflow control devices (ICDs) have been used to remediate wells. In this paper, two field examples of using tubing ICDs are discussed, one inside a wire wrapped screen liner and the other inside a liner deployed ICD system.

Liner failures were diagnosed by analyzing the temperature data from fibre optics along with the performance indicators of the ESP pumps. Various remediation plans such as patching the failed intervals, using tubing ICDs or drilling a parallel lateral were considered. Using tubing deployed ICD systems along with blanked intervals was selected as the most practical solution to recover productivity from these wells. To size the ICDs and length of segments, a range of emulsion production volumes as well as estimated corresponding vapor and gas volumes were assumed. Furthermore, the risk of creating new hot points near the existing failed points or vapor producing intervals was considered.

The well workovers involved detailed planning of operations and services to effectively achieve cleanouts, maintain adequate inner wellbore diameter to run the swell packers and correlate DTS data with workover findings. The workover involved gauge runs, a jet-vac clean-out, a multi-finger caliper log and mud circulation of the wellbore for final solid removal to ensure successful installation of the new ICD systems.

The wells were put on production initially with low drawdown and slowly ramped up to let the packers set and sand to form bridges. After a few months of production, the wells were fully ramped up with production rate increasing 2 to 5 times the pre-workover rates. ESP pump performances is stable in both wells and the fibre optic temperature data show that failed liner intervals and hot points are well managed.

The intent of this paper is to share the processes and factors considered in using remedial ICDs and the learnings from the workover operations and startup of the wells.

The goal of this paper is to present the philosophies for the qualification and flow loop testing of FCD nozzles as well as the macroscopic implementation and operations of FCDs in SAGD producer wells. A quantitative methodology to evaluate FCD nozzles to choke back steam will be presented. Flow loop testing data will be shown to illustrate the qualification process. We will also discuss if sand control screens should be put on the tubing deployed inflow control devices. Some modeling and field examples will be shown. In the end, field data of the SAGD producer wells installed with the FCDs will be presented. Experience to manage and operate the wells will be shared.

Accurate prediction of flow regime and flow profile in wellbore is among the main interests of production engineers in the quest of optimizing wellbore production and increasing reliability of downhole completion tools especially in SAGD projects. This study introduces a methodology for wellbore monitoring by detecting flow phase and flow regime. In order to develop this method, an advanced multi-phase flow injection experiment was designed and commissioned.

A flow injection setup was developed to test distributed fiber optic sensor installation under different operating conditions, including multi-phase flow (oil, brine and gas), and flow fraction scenarios. Different signal processing methods were applied to extract meaningful features and filter the noise from the raw signals. A statistical analysis was performed to assess the trend of the driven data. Then, typical SAGD models were simulated to assess the results of experimental setup for scale-up purpose and determination of local breakthrough of steam along the well.

Results showed that the Distributed Acoustic Sensing (DAS) data contains different levels of signals for each phase and flow regime. We also found that some level of uncertainties is involved in relating the flow regime and DAS information which could be resolved by improving the sensor installation procedure. In addition, the application of data-driven machine learning methods was found necessary to interpret the signal patterns. Initial results have shown that steam breakthrough along the well can be detected using real time DAS high energy/frequency signals. It can be concluded that including the DAS along with Distributed Temperature Sensing (DTS) is necessary to provide a better picture of steam conformance and SAGD wellbore monitoring. The limitations of the current experimental setup restricted further conclusions regarding the hybrid DAS and DTS application.

This paper is a part of an ongoing project to address the application of the combined DAS and DTS in SAGD projects. The ultimate goal is a downhole monitoring system to oversee the flow phase, flow regime and sand ingress in thermal application. The next phase will address the required improvements for developing a flow loop to handle high temperatures, include sand production and mimic thermal operation conditions.

Flow Control Devices (FCDs) are known to enhance efficiency of oil production, overall project economics and environmental performance that is currently of particular importance for Steam Assisted Gravity Drainage (SAGD) operators in Western Canada. FCDs have been utilized in SAGD wells over a decade, primarily, as liner deployed (LD) applications. Compared to LD FCDs, tubing deployed (TD) FCDs for SAGD producers are less common and require better understanding from the standpoint of completion design and operational strategy.

A study has been conducted on TD FCD installations in producer wells in the Surmont SAGD project. The study was aimed to understand failure modes and causes for several failed SAGD producers retrofitted with TD FCDs. Due considerations were given to key factors such as geology, runtime, operational practices and the possibility of failure of the slotted liner. Caliper log, fiber optics and downhole imaging data were used in the study. FCD strings pulled from the ground have been also analyzed.

All failures were found to be erosive wear with localized full wall loss of the TD FCD base pipe. No detectable erosion or other damage to FCDs are observed. As a general practice, a less aggressive operation strategy for wells with TD FCD compared to wells with LD FCDs was implemented after the study to avoid new failures. Proper screen sizing for TD FCD retrofits in slotted liner wells was identified as an important factor to provide effective sand control and may help reduce failures, but screen sizing was found not to have a direct effect on the failures investigated. The study shows that TD FCD retrofits have proven to be successful; however, special considerations are required when designing TD FCDs installations for SAGD producers, compared to LD FCDs, in order to reduce risk of erosive damage and failure.

A detailed understanding of wellbore flow is essential for production engineers in both the design of site equipment and optimisation of operation conditions. With the depletion of conventional resources, the need for unconventional extraction techniques to leverage untapped reserves has seen the generation of new downhole flow conditions. In particular, the extraction of natural gas from coal seams has led to scenarios where liquid removal from the reservoir can cause the development of a counter-current multiphase flow in the well annulus in pumped wells. In this work, high-fidelity computational fluid dynamics is used to capture the momentum interaction between gas and liquid phases in such a flow configuration, allowing for the evaluation and modification of closure relations used in upscaled models.

The computational fluid dynamics model is based on a recently proposed formulation developed using phase-field theory in the lattice Boltzmann (LB) framework. It has been previously applied to the analysis of Taylor bubbles in tubular and annular pipes at a range of inclinations and flow directions. The robustness of the numerical formulation has been proven with a range of benchmark scenarios that extend upon previously reported results in the LB literature. Future investigations will look to apply the developed closure relations into the two-fluid model and compare with in-house experimental and mechanistic results.

Using the multiphase lattice Boltzmann model, the drag force closure relations are investigated for bubbles covering a range of parameters. This assesses the accuracy of existing closures and provides confidence in the developed computational tool. Following on from this, the size of the liquid slug behind a Taylor bubble is analysed. Comparison of the results with pre-existing relations provides a means to modify current large-scale simulators to accurately capture the momentum exchange between gas and liquid phases in a wellbore. With the improved understanding of phase interactions developed in this study, upscaling work is to be conducted through the implementation of closure models within a two-fluid-type model, not unlike OLGA, as well as in a recent mechanistic model.

The novelty of the high-fidelity computational model is in its ability to resolve high density ratio (liquid-gas) flows under complex, dynamic conditions within the lattice Boltzmann framework. Additionally, the development and validation of novel closure relations for mechanistic and two-fluid models improves the accuracy of predictions associated with wellbore operations, ultimately allowing for more optimised production.

Production forecasting is required at all stages of coal seam gas (CSG) reservoir development. Depending on the stage of appraisal or development, different methodologies can provide the best fit for the forecasting objectives. This paper compares technical advantages and disadvantages of several forecasting approaches while considering potential accuracy, time required to construct the forecast and general fit for purpose. The basis of comparison is case studies of CSG projects in the Surat and Bowen basins.

In general, a very similar set of forecasting tools can be applied to CSG reservoirs as for the conventional oil and gas fields. A notable difference is gas desorption from the source rock, which needs to be included into numerical and analytical model and is typically described by adsorption isotherms. Some approaches, like Decline Curve and Pseudo Steady State Well Deliverability can be applied with minimal modifications. Flowing Material Balance and more detailed numerical reservoir simulations require changes to account for the gas desorption mechanism. However, these tools are already well established in the industry.

In addition to comparing the established approaches for CSG production forecasting, we propose a new hybrid method and compare its applicability to the other tools. The hybrid method uses output of the numerical reservoir simulation model and applies an analytical correction to adjust the predicted production rates to the actual observed data and to produce the forecast at possibly different bottom hole pressure compared to the original numerical model. The new hybrid method is recommended in cases where a quick forecast is required for fields with a large (hundreds and more) number of wells. The advantage of the new approach is that it provides a quick response while still maintaining the characteristics of the initial reservoir model.

Flowing bottom-hole pressure (FBHP) is a key metric for optimising coal seam gas well performance and enhancement of production. Downhole pressure gauges are increasingly being used to measure the FBHP. However, they are impractical, expensive, and complex to install and maintain. Consequently, reliable measurement and prediction of the FBHP, required to forecast well production, remains a challenge. This paper aims to predict the flowing bottom-hole pressure in coal seam gas wells by taking advantage of the temporal data and advanced analytics. Data-driven models have been developed to predict the FBHP by leveraging the temporal data gathered at the surface in order to control the performance of the wells. The data used in the study was obtained from five coal seam gas wells containing seven sensor measurements gathered over 15 -18 months production period. For the prediction of FBHP, we applied linear regression and neural network-based approaches. Overall, neural networks resulted in the best predictions with the root mean squared error (RMSE) within 198 - 450 kPa for the five wells.

Reserve and formation evaluation are the basis to the development of coalbed methane (CBM) reservoirs. To date, material balance methods and productivity analysis methods are mainly used to estimate the reserve and permeability, respectively. However, there are lack of methods for determining reserve and permeability simultaneously. In this work, the typical characteristics of undersaturated CBM reservoirs during production process, such as permeability variation and expansion effect of immobile gas, are firstly considered to derive a novel flowing material balance equation (FMBE), by which the reserve and permeability can be estimated. Based on the production data at single phase dewatering stage, the control volume and reservoir permeability of the CBM reservoir can be derived by the slope and y-intercept of the fitted straight line. And then the original gas in place (OGIP), initial water reserve, initial adsorbed gas reserve, initial free gas reserve, and initial dissolved gas reserve can be determined. Verification cases show that the errors between the evaluated and actual values are small, regardless of whether there is free gas in CBM reservoirs at the initial condition, indicating that the method is reasonable and accurate. The proposed method has been used in some CBM wells in China. It has been proven to be easy-to-use, time-saving, low-cost, and with high accuracy.