Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. A very small string, usually run along the outside of the tubing and banded to the tubing. Commonly used for hydraulic control of safety valves and sliding sleeves. May also transmit bottom hole gauge data.
Martins, Ana (Nederlandse Aardolie Maatschappij) | Marino, Marco (Nederlandse Aardolie Maatschappij) | Kerem, Murat (Shell Global Solutions International) | Guzman, Manuel (Shell Global Solutions International)
This paper presents the first comparison between two different injection methods for foam assisted gas lift. Useful information for operators and technology developers are also provided concerning chemical selection, testing, and deployment of this hybrid artificial lift technology in the field.
The trials have been conducted in a gas lifted oil well with severe slugging and water cut above 50% (selection criteria as per SPE-184217-MS). The surfactant was delivered through a dedicated capillary injection string during the first trial, and the effects of surfactant concentration and depth of injection were evaluated. During the second trial, the surfactant was injected into the gas lift stream at the surface. Different surfactants were utilised for both trials based on stability concerns and method of injection.
Both trialled injection methods successfully stabilized the well flow, terminating severe slugging while increasing the drawdown and delivering an increase in gross production of circa 200%. These results, together with the downhole pressure data collected during the first trial, confirm that the surfactant starts foaming only at the depth where the lift gas enters the tubing. Injecting surfactant into the lift gas stream required higher concentrations than using a dedicated injection string, difference attributable to the slightly different chemistry, but even at those higher concentrations an anti-foamer injection was not required.
Concerning the response time, the well responded in 30 to 60 minutes with capillary string injection, while 6 to 12 hours were required for injection into the lift gas stream. This suggests that the surfactant probably moves slowly down on the annulus walls as a liquid film rather than travelling in droplets dispersed in the gas phase. Based on the outcome of the two trials, it is concluded that the injection via the lift gas stream is as effective as capillary string injection, at a fraction of the initial costs, with lower maintenance requirements, while still allowing access to the well.
Gas wells of the Bahrain Field in the Kingdom of Bahrain suffer from corrosion and scale issues due to the presence of water, Carbondioxide (CO2), and a high Hydrogen Sulphide (H2S) content in the formation. The current method applied to overcome these issues involves bullheading a corrosion inhibitor batch treatment. However, high costs and low effectiveness are driving a shift from batch treatments to continuous downhole treatment techniques. This paper describes the process of converting to continuous downhole treatments.
The process of continuously injecting a corrosion inhibitor downhole is much more efficient and cost effective than bullheading the well with a corrosion inhibitor. This application reduces the potential of scale buildup and avoids well deliverability reduction problems. Additionally, the injection system may be used to continuously inject multi-blend chemicals downhole and can thereby treat other problems downstream and reduce the need for surface inhibition.
Designing the system with the appropriate chemicals and tubing material is the key to success. The selection of materials and chemicals should take into account the CO2, H2S, temperature, and pH concentration in the candidate well.
The chemical injection string can be installed into a live well using a capillary unit, without the need to shut-in or choke-back production. This can be carried out as a rigless installation similar to a coiled-tubing operation, but on a much smaller scale. The capillary unit is small and compact, and is mounted onto a truck or a trailer. The unit can be mobilized and de-mobilized for operation rapidly and easily, saving time and cost.
Routine maintenance to the injection system is crucial for a long-term successful application. The qualification of the chemicals should be stringent and must allow for friction loss through such small inner diameters (IDs), however it must also withstand the pressures, temperatures, fluids, and extreme downhole conditions that it will face.
Using the continuous downhole injection system will positively impact well integrity, improve completion lifetime, assure production continuity, reduce downtime and treatment operating costs, and avoid coiled-tubing descaling operational costs.
Installing a downhole treatment system can also be used for other purposes if needed, such as H2S management, deliquification, scale inhibition, controlling paraffin/asphaltene, and treating downhole pumps.
There is a well-known theoretical chart that shows how compression, scales, liquid loading, corrosion, etc. appear as a gas field decreases production due to reservoir depletion. The approach of this paper is ambitious and will demonstrate and exemplify how these problems appeared in our gas field, and share the techniques, methods, and procedures we went through to satisfactorily handle them.
This paper shows the development of a gas field placed in the Golfo San Jorge Basin (Argentina) including the different life stages of the field (High/Medium/Low Pressure) with the related problems in Facilities, Flow Assurance, and Liquid Loading, and finalizes with an introduction to the future problems we are expecting.
Throughout the paper, we will show the changes we went through, lessons learned, and conclusions related to the following topics: + Facilities → Slugging in flowlines/changes in suction pressure/new facilities + Flow Assurance → Chemical usage for solving organic and inorganic scales. Need of migration from bullheading treatments to CT nitrogen assisted operations. Acid stick treatments. + Liquid Loading → Foaming agents/Velocity Strings/Capillary Strings/Wellhead Compression + Tendency of Scales Evolution in produced water. + Evolution of tubing metallography + New approaches in PLT interpretation
+ Facilities → Slugging in flowlines/changes in suction pressure/new facilities
+ Flow Assurance → Chemical usage for solving organic and inorganic scales. Need of migration from bullheading treatments to CT nitrogen assisted operations. Acid stick treatments.
+ Liquid Loading → Foaming agents/Velocity Strings/Capillary Strings/Wellhead Compression
+ Tendency of Scales Evolution in produced water.
+ Evolution of tubing metallography
+ New approaches in PLT interpretation
Not many papers cover in such an integral way the development of a conventional gas field with a large exploitation history as this work does, where the field dates from the 2000s.
This paper sets a reference and fills a gap in terms of an
Depletion of the reservoirs leads to a decrease in field production rate. Wells production rate continue to drop below the minimum critical velocity, at which point the liquid that was previously carried upward by the gas begins to fall back. The produced liquid accumulates in the well creating a static column of liquid, therefore creating a backpressure against formation pressure and reducing production until the well ceases production. Capillary Surfactant Injection (CSI) is installed on the wells to overcome the liquid loading symptom by generating foam, thereby reducing the surface tension, lowering the fluid density, and lowering critical rate.
This paper presents the comprehensive strategy of CSI application in high temperature gas well in Pakistan. Well 1A has been flowing under the critical conditions of liquid hold up with WGR of 82 bbl/MMscfd in high temperature (355 °F), deeper (11350 ft.), bigger tubing of size 5-1/2" and 7" Liner below the end of tubing along with compressor installed on it.
Based on nodal analysis, CSI was found the suitable Artificial Lift System (ALS) to deliquify this well. The procedure involved - laboratory analysis to monitor the temperature stability test of foamer (OMNIFOAM-HT) and defoamer (Alpha-2325) - scrutinizing the amount of foamer injected in the well to generate the foam - design of defoamer injection point and dosage to break the foam on surface - operational procedure - optimization mechanism - production enhancement and rapid payout time while executing CSI.
The lab results and field optimization showed OMNIFOAM worked successfully at high temperature and converted 350 - 400 barrels/day of formation water into foam at optimum injection rate of 4-5 gal/day. Defoamer injection (0.25-0.5 gal/day) was effectively carried from the injection point of corrosion inhibitor, around 150 feet upstream of compressor. CSI deployment significantly enhanced 15% rate of previous gas production and extended the life of the well to 4.0 years. If injection had been continued, the payback period was estimated to be 04 months. Based on these results, permanent deployment of CSI with renaissance wellhead system was recommended as promising solution for prolonging the life of well, sustaining its production in a short payout time and improving the reserve recovery.
The Fadhili Formation located in the Awali Field, Bahrain is a carbonate reservoir with an active water drive. Five horizontal gas-lifted wells drilled in the Fadhili with initial production rates of over 1500 BOPD began showing scaling symptoms once watercut rates increased to over 90% within a year. The scaling was found to be largely problematic as wells descaled with acid would find reoccurrences within 4 months of any treatment. Calcium carbonate scale found in both production tubing and flowlines would not only hamper production, but also damage flowline valves and leak as a result of the frequent descaling. The purpose of this study was not only to reduce the frequency of costly acid stimulation treatments, but to also inhibit the growth of scale and successfully allow for the conversion of these gas-lifted wells to annular lift without the risk of scale growth in the casing. This was done firstly by testing the extent of scale growth within the tubing and flowline through an integrated approach of combining fluid chemical analysis, system mass balance, and pipeline simulation. Differing scale inhibition methods were then considered before continuous treatment through gas lift injection was selected. Finally, an extensive production selection was then carried out to identify the optimal inhibitor composition and concentration. This paper displays a simple and low cost approach through which scale growth should be identified, classified, and then dealt with.
Continuous Foam Injection is a proven deliquification technique in gas wells, but the technology typically struggles to perform in wells with high fractions of liquid hydrocarbons. For gas lifted oil wells operating at high water cuts however, continuous downhole foam injection may prove feasible to enhance production. A field trial to test this theory was successfully executed within an oil producing facility in The Netherlands. The objective of this trial was twofold: First, to observe the changes in production owing to downhole injection of a foaming agent while keeping the lift gas rate constant. Second, to perform a lift gas utilization test to identify potential lift gas savings with the assistance of foam. Furthermore, strict specifications on the export crude and produced water had to be achieved. The trial showed successful results. The well had a fast response to the addition of foam whereby initial sluggish production stabilized. This has overcome the flow instability related production deferment, which was significant. Further increases in the foam injection rate to reach the optimum foam concentration helped the well to produce up to 20% more gross liquid than the measured and calculated stable rates. The trial has revealed that with the application of foam, lift gas savings of 35% were feasible and more could be achieved depending on the desired gross liquid production. No process facility upsets were experienced during the trial.
This paper describes the detailed aspects of the trial, including the preparation, execution, and modelling techniques which will benefit and add to the current body of knowledge of foam lift to the petroleum industry.
Patterson, Aaronica (Baker Hughes) | Francis-LaCroix, Kyethann (Baker Hughes) | Joseph, Terry Ann (Touchstone Exploration (Trinidad) Limited) | Sobrien, Teri-Ann (Touchstone Exploration (Trinidad) Limited) | Sanchez, Alex (Touchstone Exploration (Trinidad) Limited)
This paper presents a cost analysis / comparative study of the return on investment realized from the downhole chemical treatment of the Coora CO365 well. The technologies available to permanently outfit older wells that are completed with sub-surface safety valves (SSSVs), with the ability to benefit from direct down-hole chemical remediation, are also detailed.
Producing from a field that was first developed in 1936 and located in southern Trinidad, Coora CO365 experienced paraffin deposition in the near-wellbore and along the well's production string early in its productive life. The operator followed long-term strategic workover plans, but paraffin deposition still continued. Further investigation highlighted that the implementation of an optimal chemical injection program would be critical to realize maximum financial benefit from production of this maturing reservoir.
The operator has been able to replace high-cost workovers with low-cost chemical treatment, significantly improving the economics and prolonging the productive life of this well. Through comparison with older wells (in this block), completed without direct downhole means of chemical remediation, this case will show that simple modifications, though incurring upfront capital cost, can result in long-term revenue generation and early payback, if combined with an appropriate chemical remediation package. The analysis will dispel the common misconception that the cost incurred in refitting older wells with downhole injection capabilities overshadows their revenue generation prospects.
In many cases, the natural decline of a field can be exacerbated by flow-assurance issues in wells and equipment. This paper highlights the potential to sustain production in brownfields that have been plagued with these issues via the use of downhole chemical injection.
Vogelij, Nico A. (Nederlandse Aardolie Maatschappij BV) | Veeken, Cornelis A. (Petroleum Development Oman) | Islamov, Rafael I. (Nederlandse Aardolie Maatschappij BV) | Lugtmeier, Bert (Nederlandse Aardolie Maatschappij BV) | Ros, Oscar (Nederlandse Aardolie Maatschappij BV) | De Vries, Gert (Nederlandse Aardolie Maatschappij BV) | Zhidkova, Natalia A. (Nederlandse Aardolie Maatschappij BV)
In the current brown field environment a lot of mature gas wells in the Southern North Sea (SNS) are liquid loading. Foamer can be injected in the wellbore as a gas well deliquification (GWD) measure to mitigate this liquid loading behavior. Foamer can be injected periodically in batch mode or continuously downhole by means of a small capillary string installed in the wellbore. To date ONEgas* is producing 12 offshore gas wells located on 3 manned SNS platforms by means of continuous foamer (CF) injection. The first offshore CF installation came online in 2011 and dozens more installations are scheduled in the near future. CF has gone through a steep learning curve where the next step is to install CF on an unmanned SNS platform. After 4 years of gas production with CF a lot has been learned about designing, installing and operating capillary string CF installations. This paper demonstrates the success of continuous foamer injection by showing increased production and recovery due to foamer but also presents the challenges that were experienced in terms of uptime i.e. poor reliability due to capillary blockages, sand erosion and surface facility upsets etc. The method of tackling these reliability issues to maximize uptime is presented, including an overview of the current and future subsurface and surface hardware components.
Tayyab, Imran (United Energy Pakistan Limited) | Uddin, M. Farooq M. (United Energy Pakistan Limited) | Ahmed, Qazi I. (United Energy Pakistan Limited) | Ibad-ur-Rehman, M. (United Energy Pakistan Limited) | Azam, Qazi Syed Munawar (United Energy Pakistan Limited)
Liquid loading is an ineluctable problem encountered by gas wells as their reservoir pressure declines and Gas-Liquid Ratio (GLR) increases. Foam Assisted Lift (FAL) is one of the modern methods for dewatering gas wells by reducing effective density and surface tension of produced fluid. Gas lift is also a widely used method that reduces flowing bottom-hole pressure by injecting gas in the well to lower hydrostatic head. This paper proposes a combination of above mentioned technologies called Foam Assisted Gas Lift (FAGL) and recommends its' efficiency over two specific scenarios; a) when reservoir pressure is low and static liquid level remains below bottommost SPM, b) when there is a considerable liquid column in wellbore and gas injection pressures are limited due to surface constraints, injecting foam decreases the hydrostatic head and requires less gas injection pressure to offload the well. In either case, FAL can offload the well but the stabilized rates achieved are uneconomical compared to the soap requirement per day.