Saradva, Harshil (Sharjah National Oil Corporation) | Jain, Siddharth (Sharjah National Oil Corporation) | Hamadi, Masoud Al (Sharjah National Oil Corporation) | Thakur, Kapil Kumar (Schlumberger) | Govindan, Gunasekar (Schlumberger) | Ahmed, Ahmed Fadl Mustafa (Schlumberger)
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.
The Sajaa asset consists of three retrograde condensate onshore fields. All wells are naturally flowing, with support from wellhead compression to reduce the effect of liquid loading on these mature gas producers. The reservoir was blown down to produce gas associated with rich condensate, water, and liquefied petroleum gas. With the reservoir’s long production history, its pressure has been greatly reduced.
Khalid, Ali (Weatherford International Ltd) | Ashraf, Qasim (Weatherford International Ltd) | Luqman, Khurram (Weatherford International Ltd) | Moussa, Ayoub Hadji (Weatherford International Ltd) | Nabi, Agha Ghulam (Pakistan Petroleum Limited) | Baig, Umair (Pakistan Petroleum Limited) | Mahmood, Amer (Pakistan Petroleum Limited)
Carbonate platforms are one of the most common reservoirs on earth, and as such are one of the most frequently explored.
Sulaiman fold belt in Pakistan is known to contain multiple hydrocarbon bearing carbonate formations. One such formation is the Sui Main Limestone formation. The formation when first discovered was known to contain over 9.5 Tcf of gas in Sui field, and up to 5.0 Tcf of gas in the neighboring Zin field. Over the years due to extensive field development and production, the Sui Main Limestone reservoir has been driven to depletion. Operators are now looking to explore deeper horizons in the same fields.
The challenge in deeper exploration of the subject fields is now a depleted pressure of about 2.1 ppg EMW of the Sui Main Limestone formation. In addition to the low pressure, the SML formation is highly fractured in nature. These two factors resulted in massive circulation losses when an attempt to drill a well was made through the approximately 650 m width of the SML formation. To cure losses, operators resorted to heavy LCM pills, and numerous cement plugs. Losses in the hydrocarbon bearing SML formation also led to well control and stuck pipe events on multiple occasions. Successful drilling through the whole width of SML formation would sometimes take up to almost 3 months. Drilling time and lost circulation materials thus generated excessive well costs.
The operator sought a solution which would eliminate circulation losses in the SML formation, and cut down drilling time substantially. An underbalanced system was first considered for achieving these objectives but as the SML formation bore sour gas and excessive equipment would be required for a safe underbalanced operation, the option was ruled out. A nearbalanced nitrified foam system was thus designed to be able to drill the SML formation delivering the same benefits of an underbalanced operation without its perils.
By applying a nearbalanced nitrified drilling technique, operators in the subject fields were able to cut down the drilling time to about 3-5 days, achieve a substantial increase in drilling performance, and practically reduce the NPT to 0.
This paper studies the planning & design of a nearbalanced nitrified foam system for two different wells with hole sections of size 17", and 8-1/2". The paper also discusses the equipment selection, the wellsite execution, and the results achieved by applying nearbalanced nitrified foam drilling in the subject fields.
Ashraf, Qasim (Weatherford International Ltd) | Khalid, Ali (Weatherford International Ltd) | Ali, Farhad (Weatherford International Ltd) | Luqman, Khurram (Weatherford International Ltd) | Mousa, Ayoub (Weatherford International Ltd) | Babar, Zaheer Uddin (Pakistan Petroleum Limited) | Hussam Uddin, Muhammad (Pakistan Petroleum Limited) | Ullah, Safi (Pakistan Petroleum Limited)
An operator has drilled more than 32 wells to date in Adhi field, a gas and condensate field in northern Pakistan. The majority of these wells produce from depleted sands and some also produce from limestone reservoirs. The wells range in depth between 8,366 and 11,483 ft (2,550 and 3,500 m).
The operator was in the process of drilling the 8 1/2-in. hole section with the least possible mud weight to minimize the overbalance across the lost-circulation-prone limestone formation. While drilling the section, an unexpected gas pocket was encountered and subsequently required an increase in mud weight. To further add to already challenging drilling conditions, a fault was expected in the middle of the section. This fault was expected to produce total losses. The resulting loss of hydrostatic head would have caused a troublesome well-control scenario.
The above conditions led to an inherently tight drilling window. The operator thus made precise management of wellbore pressures a prime objective. However in conventional drilling, relying on the mud weight and pumping rate for accurate management of wellbore pressures proves highly inefficient, if not impossible.
A managed pressure drilling (MPD) and underbalanced drilling (UBD) hybridized system was devised to enable drilling the 8 1/2-in. hole section. An MPD system that applies constant bottom hole pressure would enable drilling the section with the least possible mud weight and as close as possible to the pore pressure line. In the event that heavy to total losses were encountered because of the predicted fault, the system could be switched over to UBD flow drilling. By switching over to UBD, the equivalent circulating density (ECD) would be reduced further and allow the well to flow while drilling and mitigating losses.
An MPD and UBD system was also expected to offer numerous benefits in drilling, including reduced chances of differential sticking, reduced formation damage, increased rate of penetration and bit life, less washouts in the drillstring and pumps, reduced nonproductive time, and enhanced abilities to execute well control with the pipe in motion without fear of getting stuck.
The MPD and UBD hybrid system was deployed to the location. The operator was able to drill the 8 1/2- in. section to the target depth. The operator commenced drilling with an MPD system but, as expected, heavy losses were encountered. Drilling then proceeded with UB flow drilling until reaching target depth. The hybrid system enabled the operator to achieve target depth, eliminate an entire casing string, and substantially reduce NPT. This paper discusses the planning, design, and execution of the MPD and UBD hybrid system.
Saradva, Harshil (Sharjah National Oil Corporation) | Jain, Siddharth (Sharjah National Oil Corporation) | Sarssam, Mark (Sharjah National Oil Corporation) | Al Hamadi, Masoud (Sharjah National Oil Corporation) | Robert, Matthew (Sharjah National Oil Corporation)
Sharjah National Oil Corporation (SNOC) currently operates 3 fractured carbonate mature gas-condensate fields with some 35 years of production history. Until recent years these fields were operated by leading International Oil Companies (IOCs) which utilised some of the then latest technologies, such as underbalanced coil tubing drilling in order to maximise the production rate.
The reservoir development and management scheme, however, did not involve gas re-injection to maintain reservoir pressure above the dew point. This led to production by simply blowing-down the field. Since there was negligible aquifer support the reservoir pressure declined rapidly and the dew point pressure was reached within 3 years, resulting in condensate drop-out in the reservoir. It is estimated that more than half of the original condensate in place still remains in the reservoir, although more than 97% of the gas in place has already been produced and the reservoir pressure have declined to around 10% of initial pressure.
In order to determine the location and quantity of condensate remaining in the field, dual porosity reservoir models were created with legacy data which replicated the naturally fractured reservoir. These models were history matched and gas injection simulation runs were performed in order to estimate the injection rates, reservoir pressure increase, field communication and potential for condensate re-vaporization and mobilisation theory at a variety of pressures. This theory was put to test and confirmed when SNOC recently performed a pilot gas injection project in one of its fields. A mixture of processed gas from the gas plant was injected and allowed to stabilise. The new mixture of injected and reservoir gas was reproduced to estimate the deliverability and ability of dry gas to vaporise the in-situ condensate. A fundamental challenge with SNOC was to determine the PVT property of the initial reservoir fluid from a surface recombined sample which made it extremely difficult to decipher the original fluid properties and history matching the reservoir model.
Utilising the field for gas storage can help elevate the reservoir pressure and increase the vaporisation of condensate, however since the field is naturally fractured it is susceptible to the injected gas fingering into a producing well. SNOC now plans to continue the next phase of the project to mature the modelling work, evaluate various sources of injection gas, understand the project uncertainties and establish the conditions required for the ECR project to be economically viable. This paper discusses the challenges, observations and its conclusion through the pilot gas injection project and its impact on the decision making for large scale implementation of enhanced condensate recoveries in the Middle East.
Maximizing field development objectives by combining various opportunities is the key to determining sustainability in the lower oil price environment. This paper demonstrates how new technology combined with large volumes of legacy data can provide the perfect platform to evaluate the potential for enhanced condensate recovery (ECR) projects and take informed decisions for operators.
The Retrograde Gas-condensate systems have always been found unique both in their flow behavior and their ultimate recovery. This is mainly because of the process of condensation that takes place around the wellbore creating a region of condensate drop out resulting in flow impedance. In addition to it, the dependency of relative permeabilities on positive and negative velocities due to coupling and inertia respectively, further complicates the flow performance. These factors, thus, make an optimum production from these systems a very challenging and difficult task. Therefore, the main aim of this paper is to present a systematic approach towards the recovery optimization of such a low permeable gas condensate reservoir in Pakistan.
There are different production enhancement techniques that are applied to retrograde systems, among which Hydraulic Fracturing (HF) is a very common exercise. This Fracturing, however, also needs the optimization of geometry (i.e. width and length) and flow (i.e. rate) parameters to make it of high value. But, in some instances, despite of the enhanced flow behavior by HF, considerable amount of valuable gas and liquid might still be lost. Therefore, the recovery can be further optimized through techniques such as Water Flood (to increase the pressure back above the dew point), Miscible Gas or CO2 flooding etc.
This study first illustrates the impact of coupling and inertia on hydraulically fractured wells, using 3D reservoir simulation on real time data. A one well sector model is initially developed after validating the history match of the whole field model. Afterwards, the data from the Hydraulic Fracturing jobs, is incorporated to evaluate the positive and negative effects of the gas velocity, along with the recommendations on frac-geometry optimization for such gas condensate reservoirs.
The paper then illustrates the application of different Enhanced Oil Recovery methods on the whole field, using detailed compositional simulation, keeping in view the limitations of hydraulic fracture - as it may not be the answer to optimized recovery. Eventually, a comprehensive strategy has been presented, summarizing all the factors having maximum influence on the ultimate recovery and illustrate the operational and economic aspects of such technologies, to increase the overall gas and condensate production from the field.
Jain, S. (Sharjah National Oil Corporation) | Al Hamadi, M. A. (Sharjah National Oil Corporation) | Alghasra, A. M. (Sharjah National Oil Corporation) | Saada, M. (Setcore Petroleum Services) | Amin, A. H. (Setcore Petroleum Services)
Cost effective management of Well Integrity is crucial for maintaining O&G production economics particularly in mature fields. Optimization of Workover resources, cost, time and associated production outage is the key for maximizing productivity. Monitoring wellbore completion through multi-tubular corrosion scanning provides the ability to operators in making this critical decision. Objective of this field trial conducted in the SNOC Sajaa field, onshore Sharjah, United Arab Emirates; was to determine thru-tubing high resolution metal loss across multiple barriers for well integrity assurance in single completion wells.
Wells operating in a low pressure envelope during later life cycle are susceptible to collapse against the original pore pressure due to the loss in wall thickness from corrosion, particularly in the case of legacy packerless completions. Quantitative measurement of thickness in the tubing and casing strings independently was addressed by a real time Magnetic Impulse Defectoscope tool. Scanning metal thickness by measuring magnetic impulse decay including the qualitative detection of the fourth barrier was achieved in the downhole gas-condensate environment. The results were interpreted to classify the average wall loss profile in this pilot project. The results analyzed and presented in this paper demonstrate the effectiveness of continuous corrosion inhibitor using ¼″ capillary strings and direct annulus injection. In addition, a deterioration comparison of tubular integrity over 10+ years of production in a high temperature low pressure corrosive (H2S & CO2) system is presented. Effectiveness and limitations of the Electromagnetic survey against Multi-Finger Caliper is compared and the importance of repeatability in well integrity testing is also demonstrated.
An insight into the metal detection accuracy through multiple tubulars and the fundamentals of well integrity assurance in mature assets is presented. Finally, evaluating the true need for intervention- method and timing, resulting in the reduction of mature well life cycle costs in the current low oil price environment.
With the majority of today's "new?? hydrocarbons increasingly found in technically challenging, complex and in many cases lower quality reservoirs, it's long since been agreed there is no more "Easy oil??. It's that fact, coupled to the industry wide challenges associated with conventionally drilled wells in mature and depleted reservoirs which have led in recent years to the very significant advances seen in the Advanced Drilling Techniques (ADT) and Technology arena.
ADT provides a suite of tools and techniques which have enabled the technical and commercial development of numerous oil and gas reservoirs worldwide which would have not otherwise been exploited. ADT comprises of the following techniques:
• Managed Pressure Drilling
• Underbalanced Drilling
• Coiled Tubing Drilling
• Through Tubing Rotary Drilling (Conventional and HPHT)
• Subsea Through Tubing Rotary Drilling
According to one recent industry report some 67% of the world's daily oil production comes from mature fields, therefore in order to not only sustain but improve upon current production levels, field life extension is not optional but an absolute necessity. Historically however, most Operators due to cost and complexity of well delivery have not fully exploited their mature assets consequently failing to reach their full potential. Therefore, in order to not only sustain but increase current production levels to meet the increasing demands, operating companies must pay greater attention to their mature fields and their resources development options.
The above coupled to the fact that in almost every conventional drilling operation there is risk, a potential to; damage well productivity (formation damage), encounter lost circulation; suffer differential sticking and many other related conventional drilling problems any of which can be exaggerated in a mature drilling environment as a function of depletion. Its here,when applied with an expert system for candidate reservoir screening, technique selection and improved reservoir evaluation technologies, ADT provides realizable and available EOR and IOR options in accessing ‘conventionally' or commercially stranded reserves. Further, when fully coordinated with the necessary subsurface disciplines an ADT solution will add measurable value by; improving production, enhancing ultimate recoverable reserves, even possibly reduce overall development cost all improving net present values.
Popular perception is we need new technology to sustain and drive the industry forward in meeting the global demands placed upon it; in truth if we look; much of the required technology is available now. The thing we, the industry, need most is the opportunity and most importantly the courage to deploy it. This paper will challenge us in our perceptions and highlight how we can mitigate the risk applying smarter drilling options such as those offered by Advanced Drilling Techniques in the hydrocarbon bearing formations.
During the last 15 years, coiled tubing drilling (CTD) projects in the Middle East (ME) have proven an efficient and economic means of increasing and sustaining production for the oil and gas industry. CTD was implemented in 1998 and since then established as a standard, viable solution for the existing re-entry challenges in various maturing fields and applications. During this time frame corresponding technologies and procedures have been developed and continuously improved to address existing and new challenges in this growing market segment.
This paper describes the use of CTD from the first activity in Oman through operations in the Kingdom of Saudi Arabia, utilizing project data collected during 15 years of operational experience. The paper includes the technology and procedural changes that addressed new and special challenges observed within the aforementioned projects and drove production from these maturing fields such as:
• The coverage of low- and high-pressure reservoirs in various fields with high temperature and high H2S challenges.
• The movement from single re-entry wells to multilateral wellbore designs, alongside the envelope extension from
pure directional wellbore placement according to plan, to real-time reservoir navigation by geo- and bio-steering
• The introduction of special applications such as ERD and precise kick off from vertical wells with coiled tubing (CT)
• The extension of drilling operations from overbalanced to fully underbalanced (UB) operation, with maximum N2
injection through the CT string and the requirement to deal with production while drilling.
• Development of other equipment to enable the pressure deployment of the BHA, allowing a move away from
conventional tower set-ups to a dedicated highly mobile coil tubing rig.
The projects resulted in constant technology improvement and implementation of new developments in all aspects of CTD technology. To achieve the necessary efficiency and economic goals for the re-entry projects, new technology must include downhole bottom hole assembly (BHA) technology, casing exit equipment, surface equipment of the overall rig and other associated equipment such as the underbalanced drilling (UBD) package. Similar to the utilized technology, the corresponding procedures were also optimized and new ones introduced to adapt to changing environments and challenges. Based on the previous and current achievements of CTD in the Middle East, this trend of adjusted developments and continuous improvements will continue to further drive project efficiencies and economics.
Sajaa gas field is one of the oldest gas fields in the Northern Emirates and Petrofac currently holds accountability for the Sajaa asset wells. This mature asset suffered from declining reservoir pressure and increased problems with liquid loading where entrained liquid dropped out in the vertical well bore, thereby restricting the flow of gas and fluids to the topside processing facility. A detailed study was conducted to understand the different techniques available for overcoming this liquid loading problem which impeded gas production rates.
After studying several methods to overcome this liquid loading issue, foamer injection was suggested for the wells which had intermittent flow patterns. The foamer application was also chosen as one of the cheapest and easiest means for overcoming liquid loading issues. Foamer treatment for Sajaa fields was initiated two years ago and a substantial increase in gas production was recorded for most of the wells with this foamer application. The foamer product selection was carried out based on modeling and subsequent lab tests. Close monitoring of well behavior to the foamer application was conducted and detailed case histories were developed for some of the wells.
A tremendous improvement in gas production rate was noted for one of the wells in Sajaa field - ‘Sajaa S-36' (9???? completion). Unlike most of the other Sajaa wells, S-36 was fitted with capillary injection tubing where the foamer chemical was injected downhole through the ¼?? tubing. The well performance was monitored for a period of one year and sufficient data was collected highlighting the foamer performance.
This paper presents the results of the foamer downhole injection campaign and gives an overview of the treatment methodology. An insight into the factors influencing the foamer performance, selection methods and the optimization techniques employed during the foamer injection trial are also presented.