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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.
Continuous-flow gas lift is analogous to natural flow, but there are generally two distinct flowing-pressure traverses. The traverse below the point of gas injection includes only formation gas; whereas, the traverse above the point of gas injection includes both the formation and injection gases. These two distinct flowing-pressure traverses and their corresponding gas/liquid ratios (GLR) are illustrated in Figure 1. There are numerous gas lift installation design methods offered in the literature. Several installation designs require unique valve construction or gas lift-valve injection-gas throughput performance. The API design can be used on the majority of wells in the US.
Extending the useful producing life of the growing universe of mature wells has become a hot topic in today's challenging oil production environment. With large reductions in new well and field development, and limited capital expenditure available for facility optimizations, prospects for production increases may appear dismal. But reasonable strategies to unlock stubborn reserves and optimize immediate production do exist. Optimizing production starts with looking critically at both downhole strategies and surface facilities. Altering downhole strategies (artificial lift pumps, gas lift, chemical treatments, etc.) has often proven effective; however, increasingly challenging wells can preclude such interventions.
A case study is described in which facilities design is shown to play an important role in providing sources of carbon dioxide (CO2) for the gas-handling process. The challenges associated with bulk CO2 storage, compression, transportation, and injection are also discussed, and an evaluation of existing technologies for CO2-handling facilities is conducted. A company initiated its first pilot project of CO2 injection as a tertiary recovery mechanism in mid-2015. The target reservoir was one of the largest oil fields in the area. The objective of this project was to assess the feasibility of CO2 injection into a carbonate formation and estimate potential additional recoverable oil.
Currently, no cost-effective method exists to efficiently, reliably, and accurately capture analog meter readings in a digital format. This paper details how artificial intelligence was used to capture analog field-gauge data with a dramatic reduction of cost and an increase in reliability. This solution was implemented in the Cheleken oil field in the Caspian Sea offshore Turkmenistan. During the field trial, operators were required to take pictures of the gauges at given intervals and upload the photos to the application. After an innovative process of calibration, the acquired images were processed using artificial intelligence and deep-learning computer techniques.
Zhang, Jianbo (China University of Petroleum (East China)) | Wang, Zhiyuan (China University of Petroleum (East China)) | Duan, Wenguang (China University of Petroleum (East China)) | Fu, Weiqi (China University of Petroleum (East China)) | Sun, Baojiang (China University of Petroleum (East China)) | Sun, JinSheng (China University of Petroleum (East China)) | Tong, Shikun (China University of Petroleum (East China))
Summary Hydrate formation and deposition are usually encountered during deepwater gas well testing, and if hydrates are not detected and managed in time, a plugging accident can easily occur. In this study, we demonstrate a method for estimating and managing the risk of hydrate plugging in real time during the testing process. The method includes the following steps: predicting the hydrate stability region, calculating the hydrate formation and deposition behaviors, analyzing the effect of the hydrate behaviors on variations in wellhead pressure, monitoring the variations in wellhead pressure and estimating the hydrate plugging risk in real time, and managing the risk in real time. An improved pressure‐drop calculation model is established to calculate the pressure drop in annular flows with hydrate behaviors, and it considers the dynamic effect of hydrate behavior on fluid flow and surface roughness. The pressure drops calculated at different times agree well with experimental and field data. A case study is conducted to investigate the applicability of the proposed method, and results show that with the continued formation and deposition of hydrates, both the effective inner diameter of the tubing and the wellhead pressure decrease accordingly. When the wellhead pressure decreases to a critical safety value under a given gas production rate, a hydrate inhibitor must be injected into the tubing to reduce the severity of hydrate plugging. It is also necessary to conduct real‐time monitoring of variations in wellhead pressure to guarantee that the risk of hydrate plugging is within a safe range. This method enables the real‐time estimation and management of hydrate plugging during the testing process, and it can provide a basis for the safe and efficient testing of deepwater gas wells.
Petroleum production from the Vaca Muerta formation represents a significant portion of Argentinian supply, so it is crucial to accurately estimate hydrocarbons reserves. The production rate of oil and gas wells in unconventional reservoirs typically declines over time. Decline curve analysis (DCA) is an empirical method that involves fitting rate line trends to history-match flow rates, to forecast future production decline, and to calculate the estimated ultimate recovery (EUR) per well. One of the limitations of modern DCA methods resides in the assumption that the choke size at the wellhead remains unchanged; this assumption is seldom true. In fact, choke size is incrementally changed by operators for two main reasons: drawdown management and hydrocarbons market supply and demand. In gas-producing wells, increasing the choke size results in a sudden increase in gas flow rate, whereas decreasing the choke size results in the opposite effect. Thereafter, changes in choke size result in a discontinuous curve of flow rate as a function of time. Under these challenging conditions, applying DCA methods to fit rate-time curves is not straightforward.
In this study, we first investigate the possibility of normalizing rates by choke size. To do so, we invoke an empirical equation that relates production flow rates to choke size. This equation is often referred to as Gilbert’s equation. Results show that choke size normalization removes the discontinuities observed in gas rates over time. A Duong model is then fitted to the normalized rate curve to forecast production and to calculate the EUR. Several examples from the Vaca Muerta shale demonstrate the successful application of this simple, fast, and practical technique in modeling hydrocarbon production and in evaluating reserves. The dataset under study consists of 16 horizontal gas-producing wells drilled in two neighboring regions. These wells targeted the lower layers of the Vaca Muerta shale that are referred to as lower Vaca Muerta and Cocina. Results show that production models change based on the location of the wells and based on the targeted shale layers. To put it in a nutshell, this paper presents a novel method for improved production forecasting and reserves estimation by considering the effects of choke size changes on hydrocarbon flow rates.
Alsaeedi, Ayesha Ahmed Abdulla Salem (Adnoc Onshore) | AlHarethi, Fahed Ahmed (Adnoc Onshore) | Alzeyoudi, Mohamed Ali (Adnoc Onshore) | Al Bairaq, Ahmed Mohamed (Adnoc Onshore) | Reddicharla, Nagaraju (Adnoc Onshore) | Soni, Sandeep (Weatherford International) | Tripathi, Deepak (Weatherford International) | Hidalgo, Melvin (Weatherford International) | Raj, Apurv (Weatherford International)
Within a complex and dynamic production system with several operational challenges, maintaining a steady stream of throughput to meet the production targets based on the day to day well availability is a key business driver. This paper discusses an all-inclusive integrated modeling approach to evaluate the supply side of the production value chain, i.e. reservoir & well deliverability and the demand side, i.e. production targets.
The process starts with the representative inflow reservoir performance and well performance generation. In the second step, the key business requirements are applied as quantified parameters such as shareholder guidelines, minimum well production, and maximum drawdown. The most conservative figure was taken to ensure the long-term reservoir health. Subsequently, the target production was estimated from each reservoir based on the current strategic business plan. Lastly, an allocation mechanism was applied, honoring the required target-production and the well capacity to give a unique solution.
The major output of the entire process was achieved by estimating the well targets and probable shortfalls, honoring the process constraints within the production system. Also, the output of this target estimation was transferred to the surface network simulation to consider the back pressure impact and provide adequate outputs such as choke settings and wellhead pressure settings.
This outlines process provides a standardized approach that is utilized to cater the several business needs, such as minimizing the liquid loading, optimizing the drawdown to maintain a stable reservoir performance, and health.
Starting from producing layers to the delivery point, this process uses an integrated approach encompassing the various components in a complex production system such as reservoir capacities, fluid composition, well behavior and network capacities to assure a representative forecast. This approach is crucial in a gas-producing operating asset as the fluctuation in demand can be easily fulfilled using a seamlessly integrated approach that takes care of the dynamic operations variables such as well availability, surface facility back pressure, etc. in a single platform.
The approach improves the efficiency of target estimation significantly as the previous tiresome work of updating the simulation models and running the isolated calculation have been replaced with few clicks within the workflow.
This holistic approach is in line with the overall corporate strategy of integrated reservoir management (IRM) guidelines ensuring the long-term development plan and strategy is inherent to the overall process.
Yugay, Andrey (ADNOC Onshore) | Vorozhikhin, Sergey (ADNOC Onshore) | Daghmouni, Hamdi Bouali (ADNOC Onshore) | Salem Al Shamsi, Marwan Hamad (ADNOC Onshore) | Yousef Alblooshi, Abbas Ahmed (ADNOC Onshore) | Silchenok, Mikhail (ADNOC Onshore) | Bin Ali, Azlan (ADNOC Onshore) | Al Mohammed, Edries Ibrahim (ADNOC Onshore) | Rinaldo, Ferdian (ADNOC Onshore)
Well integrity is a combination of several disciplines integrated into the different phases of the well lifecycle with ultimate objective to prevent well control incidents. The subject of this paper is about effectiveness of various well integrity monitoring techniques at different stages of the field life. It is based on actual Company lessons learned and recent experience in managing well integrity incidents, when all barriers got lost. Wellhead pressure monitoring is one of the most popular methods of well integrity surveillance. It is based on the double barrier envelope concept: primary barrier envelope is the one exposed to pressure; secondary barrier envelope is the one that will be exposed to pressure if primary barrier fails. Therefore, once the primary barrier fails, it is expected to observe pressure at surface as an indication of the failure. Therefore each well operator has internal fit for purpose wellhead pressure monitoring system. Some specific well categories might be monitored more frequently than another due to higher risks associated with these wells. Double barrier policy is a well integrity requirement well-known world-wide. This policy applies to wells with positive pressure at surface capable to flow naturally. This policy is the basement for wellhead pressure monitoring system. However, based on the latest Company’s well integrity experience, this system is applicable for green fields only, with brand new barriers installed and tested. In case of mature brown fields after several decades of production this system may not always work perfectly. It may happen that failure of the primary barrier envelope occurs in the wells with already failed secondary barrier envelope. In this case there is no any "grace" period to respond to the failure and we immediately get a well control incident reflecting in uncontrolled release of well media through failed barriers. Therefore at some point of field development the time comes when secondary barrier envelope is not reliable anymore and additional surveillance activity has to be implemented to ensure safe operating conditions in the fields. This paper warns well operators on the potential gaps in the well integrity monitoring that may lead to the severe incidents. Those gaps may not exist at the early stages of development but appears during the "transition from green to brown" field. The paper helps to recognize the period for activating additional surveillance techniques avoiding unnecessary OPEX impact. It also describes various surveillance techniques for secondary barrier envelope including leak detection, corrosion logging and pressure testing.
Alsaeedi, Ayesha Ahmed Abdulla Salem (Adnoc Onshore) | AlHarethi, Fahed Ahmed (Adnoc Onshore) | Elabrashy, Manar Maher Mohamed (Adnoc Onshore) | Alsenaidi, Shemaisa Ahmed Abdalla Mohamad (Adnoc Onshore) | Reddicharla, Nagaraju (Adnoc Onshore) | Al Bairaq, Ahmed Mohamed (Adnoc Onshore) | Soni, Sandeep (Weatherford International) | Raj, Apurv (Weatherford International) | AlKuwaiti, Hamda (Weatherford International) | Tripathi, Deepak (Weatherford International)
Liquid loading is one of the biggest challenges in operating gas condensate wells of a depletion reservoir. Analyzing this bottleneck using physics-based model estimations is one of the key methodologies in an integrated digital production system, which can help users to take preventive actions, thereby saving cost, time, and efforts considerably. This paper demonstrates the identification of the liquid loading condition in existing producing gas condensate wells using the analytical tools and automated workflows in an integrated framework.
The analytical workflow to investigate liquid loading bottlenecking requires calibrated and representative well models as a first step. These representative well models incorporate a tuned compositional PVT model as a fluid parameter model, and such model outputs match with wells deliverability and historical production trends. Subsequently, the calibrated models are then integrated into a digital platform consisting of automated well analysis workflows. Along with various well performance parameters being analyzed, two key parameters for liquid loading debottlenecking, such as critical unloading velocity and the In-situ velocity, are investigated in the IAOM (Integrated Asset Operation Model) system for each well as the function of depth along well's completion. Furthermore, advanced dashboards present the analysis output in an instructive manner, driving user's engineering judgment to take preventive decisions. The Integration of framework with various corporate data sources provides a continuous stream of representative data that is utilized to estimate wells deliverability under the pre-defined operating envelope.
As a result of the analysis, gas condensate wells that are suffering from liquid loading were identified using the integrated digital framework. Based on the production history and target monitoring, it was observed that these wells were unable to produce as their expected objectives. Identified wells were run through the production gas rate sensitivity analysis using the analytical tool, and as an outcome, the optimal production rate was calculated. Producing the well below this critical rate causes the In-situ velocity to drop below critical unloading velocity. Additionally, using the tuned and calibrated network model, the operating choke was identified to maintain the stable flow in the well and avoid further liquid loading. This choke size was provided to field operation for implementation and, thus, saved the cost and man-hour spent during the flowing gradient surveys. The case study demonstrates significant production improvements observed for these wells, thereby assisting the operator in reducing cost and time significantly.
Using Integration of latest production optimization platforms not only provides tools to identify wells which are currently experiencing liquid loading problem but also healthy wells which might come across liquid loading problem in the course of production, thus helping in taking proactive remedial action. Furthermore, the integrated framework provides erosional velocity related data, which acts as a guideline while optimizing gas production.