The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.
Gas-assisted plunger lift (GAPL) could be an effective and economically favorable artificial lift (AL) method to be considered during the AL life cycle for North American shale wells. The main advantage of GAPL is that it improves the well production by reducing liquid fallback and boosts the plunger efficiency through gas injection and increases the gas lift efficiency by assisting in delivering the slugs to the surface. The objective of this study is to capture the GAPL dynamic behavior through a transient multiphase flow simulator. The entire GAPL production cycle was modeled, including plunger fall, gas injection, pressure buildup, and production. First, the GAPL well production history was analyzed to evaluate the well operating condition. Then, a transient simulator was used to model the well flow behavior and production performance with GAPL. The study demonstrated the GAPL impact on flowing bottomhole pressure and the improvement in the well productivity.
A Delaware Basin well case study demonstrates the benefits of dynamic modeling and provides a comprehensive comparison between dynamic simulation results and field data. The simulation work provides insights into the fluid flow, GAPL behavior, and pressure and rate transients of a GAPL well.
The modeling results were validated against field data. A commercially available transient multiphase flow simulator was used and produced outcomes that were in alignment with field data collected. The dynamic plunger cycles were reproduced in the simulation, and the results showed the benefits of GAPL in a typical shale oil well. This could extend the gas lift life by delaying the transition to rod pumps or potentially act as an end-of-life AL solution. In the long term, this reduces the overall AL life cycle cost. The use of transient simulation helps validate AL design concepts, especially for unconventional wells where the flow behavior is very dynamic. This study encourages the use of this analysis in the AL selection workflow to help optimize the overall AL life cycle cost and maximize the net present value (NPV).
Mhemed, Mohamad (Mabruk Oil Operation) | Elrotob, Nagib (Mabruk Oil Operation) | Elsadawi, Abubakr (Mabruk Oil Operation) | Ben Abdalla, Mohamed (Schlumberger Oilfield Services) | Sherik, Ayoub (Schlumberger Oilfield Services)
For two wells, performing continuous N2 lifting in an offshore environment for weeks to produce a large quantity of aquifer water that had crossed into oil-bearing zones during a long shut-in period would involve high operational and logistical risks and require a large capital investment, which was not proven economical. As an alternative, a Rigless coiled tubing (CT) gas lift system, which uses gas cap energy, was chosen as an efficient, reliable, and cost-effective technique to revive oil production from the two offshore wells.
The technique involved running CT inside the production tubing. The CT was then hung up on an additional tubing hanger installed on the production tree. The injection rate and injection pressure were supplied by a choke manifold connected to a gas well that had high wellhead pressure. The gas was injected down continuously through CT, which lifted the standing water in the production tubing annulus to surface. Production logging tools, simulation models, and flow performance applications were used to
Estimate the volume of water crossed into oil-bearing zones Identify the time needed to revive the wells
Estimate the volume of water crossed into oil-bearing zones
Identify the time needed to revive the wells
The CT gas lift system was found to be the most efficient and cost-effective way to revive production from dead wells. In this application, the free available energy of the only gas well in the field, which was drilled in the gas cap, was used to supply the required gas rate and injection pressure.
The following steps were completed with the collaboration of all parties:
Successful installation of CT in production tree via additional retrievable tubing hanger Gas pressure and gas rate supplied and controlled by a choke manifold Real-time support to guide the operation towards success Successful retrieval of CT when the operation was over
Successful installation of CT in production tree via additional retrievable tubing hanger
Gas pressure and gas rate supplied and controlled by a choke manifold
Real-time support to guide the operation towards success
Successful retrieval of CT when the operation was over
As expected, each well took nearly 45 days of continuous lifting to reach the pre-estimated water cut for the wells to be self-lifting. CT was then successfully retrieved, and the wells continued flowing naturally with considerable rates. The oil rate gain for both wells was around 4,000 BOPD.
This methodology has been approved and adopted by the operator for future similar cases as a cost-effective method to revive oil production from dead wells.
The novelty of the technique comes from the utilization of gas cap energy in the form of high wellhead pressure of the only gas well in the field, which was drilled in the gas cap, as a source of injection pressure and injection rate. This innovative technique made reviving dead wells possible without changing wellhead configuration or investing in weeks of costly N2 kickoff operations.
Alshmakhy, Ahmed (Abu Dhabi National Oil Company) | Al Daghar, Khadija (Abu Dhabi National Oil Company) | Punnapala, Sameer (ADNOC Onshore) | AlShehhi, Shamma (ADNOC Onshore) | Ben Amara, Abdel (Silverwell Energy) | Makin, Graham (Silverwell Energy) | Faux, Stephen (Silverwell Energy)
Majority of the world's gas lifted wells are under-optimized owing to changing reservoir conditions and fluid composition. The gas lift valve (GLV) calibration is required with changing conditions. Apart from that, an allowance needs to be kept so that the valve change remains valid for longer time. Compounding this, when adjusting gas lift parameters, it was not easy for the gas lift operator to make data-driven decisions to assure continuous maximized production. These challenges are further amplified with dual completion strings: fluctuating casing pressure; unpredictable temperatures due to the proximity of the two strings; and inability to individually control the injection rates to each string. String dedicated to the formation with lower productivity and reservoir pressure tends to "rob" gas from other string. Operating philosophy in such cases end up producing from one string. Production optimization in such cases requires frequent intervention with attendant costs and risks thus presents an opportunity to re-imagine gas lift well design.
ADNOC in collaboration with Silverwell developed a Digital Intelligent Artificial Lift (DIAL) system, which consists of multiple port mandrels to be placed at GLV depths. These mandrels are connetced to the surface operating system with a single electrical cable. The ports can be selectively opened or closed by sending an electric signal from the surface unit. In addition, pressure and temperature sensors are also placed which help record these parameters in real time. Such a system enables the choice of depth, injection rate, loading and unloading sequence controlled from the surface. Realtime optimization is possible as pressure/temperature data helps draw accurate gradient curves. This system makes gas lift optimization possible in dual gas lift wells.
It has been estimated that this technology delivers a production increase approaching 20% for single completion wells, and exceeding 40% for dual-string gas lifted wells. Recognizing this opportunity, a business case and implementation plan were developed to pilot a dual-string digitally controlled gas lift optimization system.
This paper will describe, the screening phase, business case preparation, risk assessment and validation process, leading to this 1st worldwide implementation of a fully optimized dual completion gas lifted well. Implementation plan of novel digital gas lift production optimization technology in an onshore dual completion well. The completely original approach increases safety, efficiency, operability and surveillance.
90% of Field T production relies on Gas lift as means of artificial lift. Typical surveillance strategy in assessing the health of the gas lifted wells is to deploy flowing gradient survey (FGS) in tandem with surface welltest. However, in the case of Field T, this technology meets its limitation in investigating prolific wells due to its current well mechanical condition and dual string completion environment. Welltracer technology application in the field has broken the barrier in evaluation of these wells in Field T.
The Welltracer application is a non-invasive data acquisition method which measures the travel time and concentration of the CO2 return which is introduced upstream of the gas lift header. The interpreted results allow for the identification of injection points and rate. This simple idea opens up opportunity for gas lift performance evaluation of wells in Field T that was not possible through the conventional approach of FGS. This breakthrough is vital for Field T as some of the wells are facing either one or more of the following problems i.e. dual string wells with gas robbing issues, tubing leak, restricted tubing due to pack-off and multi-point injection.
Twenty-three surveys and analysis were completed during the first application in Field T. The opportunity identified from the survey were categorized depending on the resources and timeframe required to execute the changes. Four enhancement opportunities were identified which only required surface valve manipulation were executed immediately and showed instant results. Other than additional barrels, the results of the campaign have a tremendous value of information that changed the earlier comprehension of the existing problems in some of the wells.
This paper discusses the results of the application of the technology in Field T. This paper will also elaborate on the lessons learned and improvement recommendations in terms of project identification, execution and planning. Another important highlight that will be discussed is the limitation and assumptions made to further enhance the understanding of the Welltracer technology.
In the onshore field in the Northern part of Thailand, the wells are typically produced with gas lift and converted to beam pump later, using the annulus space for gas separation. In the past, the completion string must be replaced to switch to beam pumps. However, with the new Hybrid completion, the existing completion can be used, and the amount of workover is reduced. In the new Hybrid completion, two sliding sleeves are installed in the tubing string, allowing us to utilize both artificial lift methods without replacing the tubing. To produce the well with gas lift, both sleeves are closed, and the well is produced normally. When converting the well to be produced with a beam pump, both sliding sleeves are opened, a plug is set above the lower sleeve, and a downhole pump installed above the upper sleeve. This forces the wellbore fluid to flow out to the annulus through the lower sleeve. Since the liquid level is higher than the upper sleeve, most of the gas travels up the annulus while the liquid traverses through the upper sleeve from the annulus into the tubing. The liquid is then pumped along the string with a beam pump. This method acts as a gas separation mechanism to prevent gas lock and reduce efficiency problems for beam pumps. The flexibility to switch between the two artificial lift methods allows us to handle the dynamic wellbore and reservoir conditions more efficiently. The Hybrid completion has enabled us to (1) handle a wider well productivity range, (2) significantly lower the cost of workover, (3) decrease the hazards exposure during operations, and (4) produce oil and gas faster, favoring the economic return.
A novel analytical-numerical hybrid model introduced in SPE 191444
As a common occurrence in production operations, liquid-rich horizontal gas (and gassy oil) wells in unconventional plays develop severe instabilities at different stages of their well life. In this novel work, we first quantify the three-phase gas-oil-water multiphase flow behavior leading up to the characteristic severe loading signatures in order to better understand the dynamic heel-dominant liquids loading. Then, we demonstrate how a simple analytical diameter-and-inclination-dependent critical gas velocity equation can be used to determine the onset of the severe loading instabilities in a variety of artificial lift/liquid loading mitigation strategies, namely end-of-tubing landing (EOT), tubing/casing sizing, gas lift variations and tail pipe/dip tube. Actual high frequency bottom hole pressure data along with measured surface conditions will be used to evaluate the slugging behavior and recreate using analytical multiphase flow simulator. The flow conditions will be extrapolated to the heel/near lateral section of the well and simulated for various lift strategies.
Usop, Mohammad Zulfiqar (PETRONAS Carigali Sdn. Bhd.) | Suggust, Alister Albert (PETRONAS Carigali Sdn. Bhd.) | Mohammad Razali, Abdullah (PETRONAS Carigali Sdn. Bhd.) | Zamzuri, Dzulfahmi (PETRONAS Carigali Sdn. Bhd.) | M. Khalil, M. Idraki (PETRONAS Carigali Sdn. Bhd.) | Hatta, M. Zulqarnain (PETRONAS Carigali Sdn. Bhd.) | Khalid, Aizuddin (PETRONAS Carigali Sdn. Bhd.) | Hasan Azhari, Muhammad (PETRONAS Carigali Sdn. Bhd.) | Jamel, Delwistiel (PETRONAS Carigali Sdn. Bhd.) | Ting Yeong Ye, Diana (PETRONAS Carigali Sdn. Bhd.) | Abdulhadi, Muhammad (Dialog Berhad) | Awang Pon, M Zaim (Dialog Berhad)
Reservoir G-4, a depleted reservoir in field B had been producing from 1992 to 2015 with a recovery factor of 30% before the production was stopped due to low reservoir pressure. Due to the huge inplace volume. A secondary recovery screening was conducted and gas injection was identified as the most suitable solution to revive G-4 reservoir due to its low cost impact of 0.4 Mil. USD whilst managing to deliver the same results as other solutions (i.e. Water injection & Water Dumpflood).
The project had utilized existing facilities in field B including a gas compressor. The project required only minor surface modification to re-route gas into the tubing of injection well BG-03. From simulation results, a continuous injection of 5 MMscf/d will increase the reservoir pressure by 150 psia in 9 months, with incremental potential reserves of atleast 5.0 MMstb from the benefitter wells, BG-02 & as well as incoming infill wells BG-14 & BG-15. It is also envisaged that with future development of additional infill wells, the recovery factor will be increased up to 60%.
In term of gas management, field B is able to deliver additional 15 MMscf/d post petroleum operation reduction (i.e. Fuel Gas, Instrument Gas & Gas lift). With the initiation of gas injection, the project had managed to utilize and optimize 33% of additional gas production for reservoir rejuvenation purposes.
The paper provides valuable insight into the case study and lesson learned of maximizing oil recovery through gas injection with minimal cost incurred. The approach is highly recommended to maximize oil recovery especially in mature fields with similar reservoir conditions and production facilities.
Simonov, Maksim (Gazpromneft Science & Technology Center, Peter the Great St. Petersburg Polytechnic University) | Shubin, Andrei (Saint Petersburg State University) | Penigin, Artem (Gazpromneft Science & Technology Center) | Perets, Dmitrii (Gazpromneft Science & Technology Center) | Belonogov, Evgenii (Gazpromneft Science & Technology Center) | Margarit, Andrei (Gazpromneft Science & Technology Center)
The topic of the paper is an approach to find optimal regimes of miscible gas injection into the reservoir to maximize cumulative oil production using a surrogate model. The sector simulation model of the real reservoir with a gas cap, which is in the first stage of development, was used as a basic model for surrogate model training. As the variable (control) parameters of the surrogate model parameters of gas injection into injection wells and the limitation of the gas factor of production wells were chosen. The target variable is the dynamics of oil production from the reservoir. A set of data has been created to train the surrogate model with various input parameters generated by the Latin hypercube.
Several machine learning models were tested on the data set: ARMA, SARIMAX and Random Forest. The Random Forest model showed the best match with simulation results. Based on this model, the task of gas injection optimization was solved in order to achieve maximum oil production for a given period. The optimization issue was solved by Monte Carlo method. The time to find the optimum based on the Random Forest model was 100 times shorter than it took to solve this problem using a simulator. The optimal solution was tested on a commercial simulator and it was found that the results between the surrogate model and the simulator differed by less than 9%.