Multiphase flow meters are available from sometime, however, there still remain unresolved challenges. Dependable flow sensing is essential for reservoir management and production optimization. Most commercial water-cut and multiphase flow meters have limitations while measuring over the full range of flow conditions. Exiting meters need recurrent calibration, and have significant capital and operational overheads. In this paper an ultrasonic tomography based meter for water hold-up measurement is presented and the the experiences and challenges of testing the system in the field are shared. The designed system has the potential to resolve the shortcomings of available multiphase metering solutions.

Dragon Oil operates the Cheleken field in the Caspian Sea offshore Turkmenistan. The production system consists of multiple wellhead and manifold platforms, a complex network of infield carbon steel and flexible flowlines to handle production from HP and LP systems and a 30" × 40 km TL to transport the produced fluids to the CPSF (Central Processing and Storage Facility) located onshore. In addition to the complexities of the flowlines network, the development has a number of unique features that pose challenges to the daily production operation activities such as: - Relatively low reservoir temperatures; - Waxy oil with high WAT (Wax Appearance Temperature) and Pour Point; - Complicated bathymetry of the 30" TL (Trunkline); - Complex reservoirs leading to uncertainty in rates; - Increasing water production; - Increasing sand ingress; - Necessity to commingle water from different sources in the flowlines; - Corrosion, erosion and emulsion occurrence; While management of any of the Flow Assurance issues is well understood on stand-alone basis; there is no definite guidelines to manage them simultaneously through understanding their impact on each other. Obtaining flawless understanding of the nature and extent of each of the impediments issues was a key element for Dragon Oil's team to innovate this approach to minimizing the overall negative impact on production operations. The approach has been developed based on balancing the hydrophobic, hydrophilic and molecular properties of the produced fluids in correlation with the physical criteria of each of the issues to minimize the impact on the others. This paper presents the key elements of a novel approach developed to control the impact of some issues and maintain the deliverability and integrity of the 30" TL. The approach consisted of the following activities: Conducted thorough and rigorous fluids’ analyses; Generated comprehensive operating pressure-temperature envelop during different operational and ambient conditions in the 30" TL; Constructed the occurrence envelops of Flow Assurance issues focusing on wax deposition and severe slugging; Ensured adequacy of slug catching capability at the CPSF and proper procedures to operate; Controlled gas rates to generate severe slugging in the 30" TL; Monitored the performance of the 30" TL (and eventually the system) through close observations to the changes in the key controlling parameters e.g . pressure drop, outcomes of pigging operations and efficiency of separation.

Gas lift plays a major role in the oil production operations of mature depleted fields of various E&P companies worldwide. Likewise, in Oil India Limited, India about 48% of producing wells of Upper Assam Basin are on gas-lift assistance. In this project, we have started and completed a gas-lift optimization campaign in Hapjan field, one of the brown fields of Oil India Limited. This project includes complete problem troubleshooting and optimization study of all the 23 gas lifted wells of the mature field. All gas lifted wells of the Hapjan field are intermittent lift by design and are operating with surface intermitters. As such, all available diagnostic tools developed and available for intermittent gas-lift well optimization are aggressively used during this campaign. The used tools are as mentioned below: Two-pen pressure recordings. Gas volume measurements. Acoustic surveys. Downhole pressure/temperature and long cycle surveys. Revamping of compressor station. In the present optimization campaign, entire candidate wells of Hapjan field were included and the endeavor has resulted in crude oil production gain of 76 m3 / day , which is 11.8% growth of the total production of the field. In addition, based on the results of the comprehensive study of vertical regime of the wells, 3 wells have been taken up for recompletion. Moreover, the gas volume in the injection gas network have been increased from 280000 Scmd to 340000 Scmd with the commissioning of a new compressor, and by revamping of the all other compressor units of the station. This has further supported to reallocate the required gas quantity in each individual well as per the design volume. The technical experience and knowledge gathered from this gas lift optimization campaign certainly confirms that optimization of gas lifted wells is a vital tool to boost up production in mature depleted fields in Oil India Limited as well as in other exploration and production (E&P) operators worldwide.

Applications of oil-in-water emulsion (O/W) emulsification technology in enhanced recovery and pipeline transportation of heavy oil can be limited by several factors including salinity of the reservoir or process water, process temperature, and water cut. In this investigation, laminar flow of O/W was simulated in a pipeline to investigate the effect of salinity of aqueous phase (NaCl) and water cut on flow characteristics of the fluid. The case was simplified by considering the O/W as a stable, pseudo-homogeneous, single-phase fluid within the conditions operated. Pertinent to the objective of the study, at flow reference temperature, Tref = 30oC, the pressure drop at 30% water cut was 931Pa compared to 84.6 Pa at water cut of 50% (reference working fluid without NaCl). In contrast, the pressure drop was 239Pa, 142Pa, 124Pa, and 82.9Pa at 70000ppm, 40000ppm, 20000ppm, and 10000ppm salinity in the aqueous phase, respectively. In addition, the maximum dynamic viscosity imposed by the fluid, was ≈81000cP at 30% water cut compared to ≈14000cP from the reference fluid. The dynamic viscosity obtained from 70000ppm salinity content was ≈34000cP. Moreover, the results confirm facile application of emulsification technology for pipeline transportation of bitumen from large reduction in pressure drop (99%) regardless of the water cut and salinity.

The present paper is concerned with an experimental study of the acoustic signature of phase inversion in an oil-water mixture system. The system studied was used to correlate the process of phase inversion with the acoustic field generated during the two fluid mixing. The experimental results revealed that the relation between the acoustic fields produced by a water continuous dispersion and the phase inversion has a clear and different signature from an oil-continuous system using a batch mixing system. This dynamical characteristic of the phase inversion phenomenon could be of use in practical systems to detect phase inversion when it occurs based on the acoustic field measured in the subject process.

The surface choke has been utilized in the oil industry to control withdrawal rates per well and to optimize production especially after water breakthrough. However, as found out from this study, applying undue restrictions in horizontal wellbores intersecting high permeability features can have an adverse impact on well performance and unnecessarily lock oil potential. This paper investigates the effect of surface choke on water cut and flow contribution along horizontal wellbores that encountered natural fractures and high permeability streaks (Super-Ks). The study considered different down-hole completions; open-hole and cased-hole. The investigation was carried out using Multi Phase Flow Meter (MPFM) measurements at different choke sizes in addition to production logs (FSI), wellbore simulation modeling, and real-time data. Instant data monitoring was instrumental in insuring stabilization of sub-surface static pressure while performing many rate tests at different choke sizes. Moreover, it flagged the role of rate stabilization on water cut behavior and rate data quality. The presence of conductive fractures and Super-Ks substantially influences the flow profile and water cut of horizontal wellbores. These features create high permeability conduits along wellbores such that they dominate production and may cause some matrix sections to contribute little or nothing as observed on FSI profiles. The effect of fractures on production from less permeable sections in the wellbore was investigated at different operating rates using horizontal wellbore simulation modeling. Both MPFM measurements and FSI logs showed that water cut from horizontal wells, affected by fractures and/or Super-Ks, can decrease if they're flowed at higher rates. Upon reviewing and analyzing data from numerous FSI logs, the study has been able to relate the water cut and surface choking to the well productivity index (PI). Consistently, wells with PI more than twice the averaged matrix PI were found to always perform better at bigger choke sizes. By choke relaxation, the water cut decreased by up to 22% while increasing oil production. Wellbore modeling also suggested that the influence of a fracture on flow contribution from remaining sections in the wellbore can be minimized if the well is operated at higher rates. Restrictive surface chokes were found to disproportionately affect lower permeability sections compared to conductive fractures or Super-Ks which in most cases were invaded by water after water breakthrough. Relaxing these surface chokes allowed more contribution of dry oil from the lower permeability sections, hence the increase in overall oil production and drop in water cut in the affected wells.

For mature oil fields with complicated reservoir architecture, reservoir surveillance is key to track reservoir performance. Reservoir surveillance may include various monitoring tools from complicated horizontal production logging tools down to regular well tests. One of the main surveillance methods is running formation pressure measurement tools such as Formation Pressure Testers (FPT) or as historically known to the industry, Repeated Formation Tester (RFT). This paper describes the use of this important tool integrated with production data to understand reservoir production and depletion behavior and hence support the Bahrain Field development plan. A study was conducted on the Ostracod and Magwa reservoirs; complicated carbonate reservoirs in the Bahrain Field. The Ostracod Zone is a sequence of inter-bedded limestone and shale in the upper Rumaila formation of the middle Cretaceous Wasia group. It is over 200 feet thick and consists of three main units: B0, B1, and B2. The Magwa reservoir is the lower member of the Rumaila Formation. It is 120 feet thick and conformably underlies the Ostracod reservoir. It consists of three main units: M1, M2, and M3. The main objectives of this study are: Evaluating pressure depletion from the initial reservoir pressure for each unit in both reservoirs, which defined the existence of flow barriers in this inter-bedded complicated carbonate. Evaluating the relationship between pressure depletion in each unit and the spacing between offset wells to the FPT location. Evaluating the Ostracod/Magwa pressure depletion per unit with time. Linking the pressure depletion to the cumulative production from the area offset by the FPT data. The results of this study helped define the depletion risk on the future infill opportunities in such complicated reservoirs. It also helped in locating highly depleted units and determining the optimal locations for the new infill wells.

Replacing all analogue sensors in the oil field is very costly and normally only a fraction of them is done. Currently, there is no cost-effective method to efficiently, reliably and accurately capture analogue meter readings in a digital format. Operators are then left with only two options: either replace them with digital (high capex) or continue with manual gathering (high opex). This paper shows how computer vision and artificial intelligence was used for the first time to capture analogue field gauges data with dramatic reduction of cost and increase reliability. This unique solution was implemented in the Cheleken Oil field, Caspian Sea, Turkmenistan. In the offshore platforms, only low-cost cameras were necessary, and gauges were identified using QR codes. During the field trial, operators were only required to take pictures of the gauges at a given interval of time 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 vision. Routine manually gathered data was compared with data collected using this solution with the following observations made: Date/time: Operators usually round time. The solution described records time on the captured pictures automatically. Value: Manually gathered data is subject to reading, typing and transcription errors. This solution has no error (provided a good calibration is done). Data Modification: Data gathered automatically with this solution has no human intervention. Therefore, is not subject to alteration, copying or duplication. Data collection with pictures was completed in 1/10th of the time that manual processes take. The business benefits from quicker operator rounds with improved accuracy in meter reading data, and time stamps. The administrative burden for operators of filling in extensive spreadsheets which are prone to error was reduced, this allowed them to collect more meter readings or be reassigned by management to more important scopes of work that bring greater value to the business. Once more it was proved that "a picture is worth a thousand words ". This solution offers an excellent opportunity for digitizing the marginal section of the field and provides a unique way to turn all analogue data into digital with a very low cost of implementation, on an infinitely scalable platform that is vendor agnostic and simple to manage.

This study presents a new method to improve production forecasts and reserves estimation for a multilayer well in the early stages of production, using Arps’ hyperbolic decline method to model the decline rate of each layer. The method can be applied to both oil and gas wells. The new approach generates the profiles of instantaneous decline rate (D) and instantaneous decline exponent (b) from the historical flow rate (q). Because of the inherent noise in the production data, a regression technique is applied to smooth the flow rate data and the analysis is performed on the smoothed data. History matching is performed not only on the profile of q, but also on the profiles of D and b. The results are the unique decline parameters (q i , D i , and b) for each layer. For a multi-layer well, the values of D and b vary with time, which means that its performance cannot be modeled using a conventional single-layer well approach. Furthermore, the well-known non-uniqueness problem from history matching is magnified in a multilayer well: many models can successfully match the production profile in the short term but fail to match it in the longer term. Only the correct model can match the profiles of q, D, and b over both the short-term and the long-term. The proposed method provides the correct unique decline parameters (q i , D i , and b) for each layer, during the early stage of production, and these parameters are then valid for the life of the well. The method works well for both synthetic examples and actual field data. The novelty of the new methodology is the ability to provide the decline parameters for each layer at an early stage of production, which can then be used for production forecasting in the long term. The non-uniqueness problem from history matching is solved.

Accurate estimation of the Original Gas in Place (OGIP) early in the reservoir life is fundamental as field development plans and ultimate recovery strongly depend on it. This is particularly relevant when the conventional material balance is not suitable due to the lack of pertinent shut-in pressure measurements. This paper presents a case history of a tight gas field in which we use flowing material balance technique and type curves for decline curve analysis to calculate OGIP by using only flowing pressure and rate data. The method uses fundamental pseudo-steady state theory, which determines that a plot of the rate-normalized pressure drop vs the pseudo-time produces a straight line with the slope of such line yielding the OGIP. The use of the pseudo time concept calls for the estimate of gas properties at the prevailing reservoir pressure which in turn is a function of the OGIP and the cumulative production. We propose an iterative scheme based on the Newton-Raphson method to compute the OGIP using the flowing material balance technique coupled with the conventional P/Z material balance. We illustrate the application of the method with the aid of synthetic examples as well as field cases obtained from low permeability gas reservoirs where no shut-in pressures are available. Results from the technique adequately compare with type-curve matching analysis. Furthermore, we demonstrate the problem can be transformed into an equivalent-liquid system and being analyzed with standard PTA techniques using the constant rate liquid solution. In absence of shut-in pressure information, the PSS analysis offers an attractive alternative to the conventional material balance method. Besides, the method only requires minimal phase behavior data in the case of gases rendering its application practical and convenient. Also, we describe how to transform the constant pressure problem into a constant rate one in order to apply standard PTA techniques. Additionally, this work demonstrates the importance of having automated wells with permanent gauges by enhancing the value of the information provided by them in the framework of an adequate and judicious reservoir management.

Knowing the source of excessive produced water from oil wells in complex carbonate reservoirs under water-flooding sheds light for engineers to optimize development plans and better design remedial actions for enhanced water management. Although oil-well water production has been studied extensively, and hence different techniques have been introduced, only a few have addressed the source of produced water. Chan (1995 ) was among first to develop diagnostic plots to analyze the water-oil ratio (WOR). Chan plots (double-logarithms of WOR & its time derivative WOR’ vs. time) can, for example, indicate whether produced water comes through water coning or water channeling. Yet, these plots were obtained from conceptualized black-oil simulations which should be validated by more diverse field data. In this paper, Chan diagnostic plots were scrutinized using a suite of diverse field data that include permeability, production logs (PLT) and pressure transient analysis (PTA) from many vertical and horizontal wells with different completions. In this study, we demonstrated that more benefit of using Chan plots to diagnose water source can be gained through incorporating other field data into the analysis such as core data, PLT, and PTA. The diverse examples presented in this study revealed that near-well reservoir characteristics play a major role in shaping WOR & WOR’ plots rather than the well being whether vertical or horizontal. We suggest that, for a more accurate Chan analysis, only the production data at constant total liquid rate should be used. The second derivative of WOR may be utilized to identify the concavity of the WOR curve or the slope of the WOR’ curve.

Conventional production logging tools proved to be efficient in vertical wells. When it comes to work in horizontal laterals production logging becomes much more complex. Common challenges are layered flow of reservoir fluid, deviation, wellbore accessibility, and stagnant zones along lateral. The tracer technology features a synthesis of a combination of marker-reporters made of a few quantum dots and a mixture of the polymer-based chemical composition. Quantum dots are nanocrystals produced using the process called colloidal synthesis. A single quantum dot is compounded of few hundred atoms and as small as 2-10 nanometer in diameter. Colloidal quantum dots irradiated with a laser emit light of different colors due to quantum confinement. The emittance of a particular specter of light can be detected using flow cytometry method. Several quantum dots joined together creates a unique and traceable marker-reporters element. There could be many unique tracer signatures (over 60). Utilization of quantum dots exclude any chance of misinterpretation while identifying tracers in samples of formation fluid. To achive superior accuracy in tracer identification we use software based on "machine learning". Qualitative and quantitative analysis of quantum dot marker-reporters in samples of formation fluid allows making informed conclusions about the performance of productive intervals of a horizontal well. Application of the technology showed the following benefits: the possibility of monitoring inflows for a long time, in contrast to a one-time logging operation; a significantly lower resource intensity and cost; confidence in conditions when the traditional downhole logging operations are complicated. Quantum dot tracer technology allows solving a number of problems, such as: post-fracturing inflow profile evaluation extended in time; assessment of each production interval in regard to water and oil production; optimization of technical solutions for well completions in the early stages of field development, such as number of ports; analysis of hydrocarbons extraction ratio; detailed information in the analysis of mutual influence of neighbouring wells in the oilfield. The application of the technology is particularly effective in the early diagnosis of water breakthrough, which allows enough time to choose the right technology for water shut off operation. Ultimately, this fact reflects in declining production rates and increasing incurred costs Major benefit is an ability to monitor production per zone at any time during five (5) years after deploying tracer-containing material downhole. Implementation of the technology is time efficient and does not require field equipment as well as crew for operation, which reflects on operating costs carried by customers.

The location of producing intervals in multi-layer reservoirs and the determination of current formation pressures in these intervals are critical aspects of reservoir management. The identified not-producing layers in multi-layer wells can be activated to start contributing to the field production. Another challenge that grows over the time during the development of a mature multi-layer reservoir is excessive water production that can be caused either due to water breakthrough over some target layers (the edge water or water from nearby injectors) or can come along the channels in cement from a water-bearing reservoir, located above or below the target reservoir. This effect impacts the vertical sweep efficiency in the field and leads to early abandonment of the wells. The common solution to avoid it is to find the source of water and perform water shut-offs based on the pre-monitoring results. A specific technology has been worked out to detect fluid flows that happen both in well and reservoir. It is based on the analysis of data acquired by broadband high-definition spectral acoustic logging tool. The acoustic signal component produced by fluid flow through the rock matrix can be distinguished from other acoustic signals caused, for example, by wellbore or channel flows by its frequency features. The layer formation pressure was determined by numeric simulation using an empirical correlation between the reservoir fluid flow velocity, pressure gradient and the reservoir-related component of acoustic power. The interpretation results were used also to track, distinguish, and quantify flows behind pipe both in reservoir and through channels in cement. Multiphase sensors were used to determine phase composition inside the wellbore. This helped to identify the source of water in well production. Three tasks mentioned above - (1) location of producing layers, (2) determination of layer formation pressure, and (3) identification of water source in the well production - described in the paper was part of the field-monitoring programme carried out to optimize well production such as gas and water shutoffs, recompletion, switching from natural to artificial lift production, and others. The target is a sandstone oil reservoir consisting of many layers with variation of reservoir rock types, permeabilities, thicknesses and formation pressures in Cheleken Block, Turkmenistan. This paper presents survey results from a number of production wells being a part of 20-well logging campaign. Producing layers were identified in surveyed wells, with some of them equipped with sand screens, which made it difficult to identify producing intervals using conventional production logging tools. These results have been correlated with permeability model. The acquired spectral acoustic data showed that not all layers of the target multi-layer reservoir were producing. Additionally, the calculated layer formation pressure values were analysed and it was discovered that in the two wells producing from the same layers the top layer had a higher formation pressure than the others. The layer formation pressure values calculated using numeric simulations proved to be in a good agreement with the formation pressure measurement data, acquired in nearby infill wells. Regarding the water source, a case with successful remeadial job have been described. This paper demonstrates how the integrated logging suite complemented by acoustic and temperature logging tools can prove effective in identifying a water source in the complicated cases such as dual-completion wells producing from a multi-layer reservoir. The acquired information was used to increase the chances for successful remedial operations. Workovers performed based on survey results allowed eliminating water production in both wells. The evaluation methodology is cost effective because it does not require wells to be shut in and it can be applied riglessly. The acquired data and integrated evaluation logs can help the reservoir development team to optimize well performance and improve reservoir management in the field.

The objective of this work is to establish a communication between the tight hydrocarbon-bearing formation and the wellbore by using high power laser technology. This paper presents different methods of utilizing the energy of the laser to enhance and improve the flow in unconventional reservoirs including tight formation, the successful results are used for field deployment strategy. High power laser is an innovative alternative to several currently used downhole stimulation methods and technologies. The system consists of the laser source which is mounted on the surface on a coiled tubing unit, fiber optics cable to transmit the energy and the downhole tool. The advantages of utilizing high power laser technology for downhole applications are the ability to control and orient the laser energy precisely. Laser energy generates heat when in contact with the rock samples, the heat impacts the rock samples by dehydrating, collapsing and dissociating some minerals near the wellbore, as well as creating micro- and macro fractures in the formation. In addition, heat removes the blockage around the wellbore and the effect extends deeper into the tight formation for production. Continues efforts over the past two decades have been proven that high power lasers provide controllable heat source while penetrating the formation, this mechanism enhances flow properties especially in tight formation. Low permeability in these formations restricts the flow and reduces production. Shale, Sandstones (including tight sandstones) and carbonate rocks have been treated with high power laser. Pre and post-treatment measurements are conducted for comparisons; the results from all rock types show improvement in permeability and flow. The results of advanced core characterizations, imaging and visualization are presented. The success of the lab experiments leads to the development of field deployment strategy to use high power laser for in-situ treatment in unconventional wells. Utilizing state-of-the-art high power lasers technology in downhole provides innovative and safe stimulation methods. Reliability, accuracy, and precision in controlling the power, orientation and the shape of the beam are some of the properties of the technology that made it attractive for downhole applications. Different tools have been developed for different applications that can fit any slim holes.

Innovation in the analysis of oil well surface measurements has led to the discovery of an instantaneous and straightforward emulsion detection calculation. When applied in the Bahrain Field, this led to the treatment of emulsion in over 100 wells, resulting in a cumulative production gain of over 500,000 barrels to date at negligible cost. Artificial Intelligence (AI) was then employed to identify and understand factors related to emulsion and optimisation treatment programs. Once the wells were treated and the method was confirmed to prove emulsion existence, a focused approach was carried out to understand it further. Wells were categorised based on their production response to standard demulsifier bullheading. In addition to a variety of well parameters, this data was used to build a machine learning model that helped identify patterns with regards to problematic zones, properties of wells with emulsion, and the best treatment method for each well. The results of the study were rather substantial and resulted in numerous new insights. Firstly, a model was built to predict the sustainability and economics of expected bullheading job treatments. This is currently being used to rank the priority of wells for either bullheading treatment or continuous chemical injection. Once the wells were classified into basic sub groups and sorted by zones, geographic analysis was carried out to identify wells with emulsion being formed as a result of waterflooding. This led to further insight into the nature of emulsion blocks, where in some cases, although it was found that these blocks exist downhole, traces of emulsion will flow to the surface and can have a unique signature. This paper discusses in further detail insights into emulsion and the different types of AI algorithms used to answer questions raised as a result of the discovery. The necessity of using machine learning cannot be overstated enough and the observations made in the paper could not have been found if it were purely by observed by the naked eye. The topic of emulsion is highly understudied, and the concept of using the emulsion detection calculation was not published before. In addition to highlighting this discovery, this paper can influence other operators to test their findings and have a real world application of machine learning in their fields.

Producing unconventional reservoirs characterized by low porosities and permeabilities during early stages of exploration and field appraisal can be challenging, especially in high temperature and high pressure (HPHT) downhole conditions. In such reservoirs, the natural fracture network can play a significant role in flowing hydrocarbons, increasing the importance of encountering such network by the boreholes. Consequently, the challenge would be to plan wells through these corridors, which is not always easy. To add to the challenge, well design restrictions dictate, the drilling of only vertical and in minor cases deviated wells. This can reduce the possibility of drilling through sub-vertical fracture sets significantly, and once seismic resolution is considered, it may seem that all odds are agents encountering a fracture network. This article addresses a case where a vertical well is drilled, in the above-mentioned reservoir setting, and missed the natural fracture system. The correct mitigation can make a difference between plugging and abandoning the well or putting it on production. The technique utilized is based on a borehole acoustic reflection survey (BARS) acquired over a vertical well to give a detailed insight on the fracture network 120 ft away from the borehole. Integrating this technique with core and high-resolution borehole image logs rendered an excellent match, increasing the confidence level in the acoustically predicted fracture corridors. Based on these findings new perforation intervals and hydraulic stimulation are proposed to optimize well performance. Such application can reverse the well decommissioning process, opening new opportunities for the rejuvenation of older wells.

Understanding the full-cycle cost of oil and gas exploration, development, and production is critical for petroleum producers and all players in the oil and gas industry. In particular, full-cycle cost assessment is used for corporate planning, acquisitions, operational improvements, project control, and risk management. The challenge is to ensure that full-cycle cost assessment is done accurately and on a consistent basis across different jurisdictions, companies, and geographic areas. Without knowing the full-cycle cost on a consistent basis worldwide, it is impossible to assess capital investment, forecast production from different areas, forecast prices, or assess other factors influencing the world market for oil and gas. This paper discusses the methodology for and the results of full-cycle cost assessment worldwide. This paper describes a methodology for full-cycle cost assessment that ensures data quality and consistency. It also provides examples of full-cycle cost assessment for major projects worldwide. The results of analysis help to predict long-term pricing trends, determine areas where production will grow or decline, and estimate capital expenditure in the next 10–20 years based on the most recent and most consistent data.

This paper presents a case study from Onshore wells in Sharjah, UAE on investigating liquid loading in 5 multilateral gas wells having various trajectories ranging from toe-up, toe-down and hybrid openhole legs. These wells are subjected to wellhead pressure reduction to maximize production rates. The main objective of the study was to evaluate the production performance for different completion designs with respect to liquid loading onset and overall production assessment with declining reservoir pressure. Dynamic multiphase flow simulator was used to conduct this study to accurately capture the details of the multilaterals system and its complex trajectories. The first step involved validating the well model with reasonable history match between the simulation and actual production data. The validated model then was used as a basis for predicting the liquid loading onset point for a given reservoir pressure decline. Multiple cases were investigated to evaluate various completion options (i.e. with or without tubing) to determine how and when the liquid loading occurs at different laterals with varying lateral trajectory. This study has showed that in such complex multi-lateral wells, laterals load up at different points in time and reservoir pressures, being affected mainly by the geometry and orientation of lateral and the production contribution. Moreover, installing tubing in these wells had the opposite anticipated effect on liquid loading by accelerating the liquid loading onset in the laterals due to the imposed additional restriction. Generally, toe-down trajectory tends to have thicker liquid film and a potential for reduced flow contribution due to liquid accumulation at the toe. These wells have a fishbone openhole multilateral network with comingled flow in the vertical section. It is observed that production tubing in the vertical section provides friction that accelerates the onset of liquid loading and hence results in decreased production for wells operating in very low reservoir pressure range. Based on overall production assessment ‘no tubing’ scenario would be more beneficial. Further, the timing of implementation of the tubing restriction later in the field life can be selected based on dynamic simulations (also evaluating economic constraints vs production gain). Transient mechanistic flow model captures the liquid loading phenomena by film reversal which usually occurs before the critical rate limit based on droplet drag forces assessment. Further, liquid loading onset occurs in the laterals first rather than the tubing section which reduces the applicability of conventional nodal analysis tools. Evaluating liquid loading behaviour in such multilateral wells with proper dynamic simulation is critical for understanding the laterals behaviour and therefore optimizing the production performance to maximize the wells uptime and ultimately the overall gas recovery as well as optimal usage of CAPEX.

Multilateral wells are considered to be an advancement revolution in the petroleum industry. The employment of multilateral wells ensured higher drainage and productivity of reservoirs through the utilization of diverse configurations. Achieving higher productivity and maximizing the reach from a multilateral well has highly improved inflow performance relationship (IPR) compared to that of a conventional horizontal well under certain conditions. Several analytical models have been developed to estimate the average oil flow rate of multilateral wells by utilizing reservoir parameters to come up with decent correlations for better accuracy. These models are accompanied with uncertainties and limitations due to the complexity of multilateral wells. Artificial Intelligence (AI) techniques have been proven to predict various parameters associated with high uncertainties in the oil industry. One of these methodologies is Artificial Neural Networks (ANN) which was utilized in this paper as new approach to predict the average oil flow rate of multilateral wells though the use of some reservoir parameters along with flowing wellhead data. As a comparable method, an analytical model was used to calculate the flow rate from several multilateral wells to quantify the value of utilizing ANN against other methods or correlations. Borisov's correlation that was developed for estimating the productivity of multilateral wells of planar configuration was used to calculate the oil flow rate of the multilateral wells and compared the results against actual average oil flow rates. Additionally, PROSPER software was utilized to estimate some wells’ parameters including Productivity Index (PI) and flowing bottomhole pressure (FBHP) for oil rate calculations. Rigorous statistical error analyses have been obtained from ANN method and Borisov's correlation. The overall regression correlation coefficient was calculated to be 0.97 for ANN which shows a strong matching between predicted and actual field values with an overall absolute error of 7.85%. High divergence was found between oil rate calculated from Borisov's correlation and the actual average oil rate with an error greater than 50%. This indicates the actual advantage of the ANN method against other correlations. This paper discussed a new method for predicting average oil flow rates for multilateral wells using surface and reservoir parameters obtained from field data via the employment of Artificial Intelligence modeling. A model was constructed for enhancing the prediction of oil flow rate for multilateral wells and resulted in a great prediction accuracy proved by field data comparison.

This paper presents the methodology of correcting the erroneous reading of the venturi meters for measuring the gas rate when high amounts of liquids, including condensate and water, are being produced from the gas wells. The proposed system takes advantage of existing infrastructure in proximity of the venturi meters and is designed to be retrofitted to the existing meters to knock out the liquid before the meter and recombines it after. This method eliminates the need for an additional flow line to carry out the liquid or a compressor to reinject the separated liquid back into the pressurized gas line.