Successful Improvement of Ultimate Recovery of Complex Deep Tight Gas Field via Combined Gas Lift De-Liquification Techniques

2021 ◽  
Author(s):  
Haitham.H Al Masroori ◽  
Abdullah.S. Al-Shuely ◽  
Nabil.S. Al-Siyabi ◽  
Salim.K. Al-Subhi ◽  
Dawood.N. Al Kharusi ◽  
...  
Keyword(s):  
Extensive Study ◽  
Significant Loss ◽  
Dew Point ◽  
Well Bore ◽  
Liquid Loading ◽  
Gas Field ◽  
Entire Area ◽  
Surface Development ◽  
Static Head ◽  
Gas Lift

Abstract The Amin top structure is Well defined in seismic data and can be easily interpreted across the entire area of North Oman. It is being identified as an extremely tight, disconnected, low porosity, low permeability, and HPHT reservoir, and thus presents unique challenges to harness its full production potential. Approximately, 15 years after production began with significant pressure depletion below dew point, a significant loss in Well productivity occurred in some of the Wells. Furthermore, during shutdowns or sudden trips of production stations, more Wells faced difficulties to restart again due to mainly, condensate banking and other probable reasons like formation water cross-flow during shut-in, which created a water bank and impaired inflow performance liquid loading due to low Well bore pressure which caused higher static head at the Well tubing. Common practice of N2 lifting CTU becoming no economical with increase number of Wells suffer from Liquid loading and represented a major challenge to look for cheaper economic alternatives. To reduce the higher OPEX associated with nitrogen lifting of Wells, multiple options were considered and evaluated thoroughly including extensive study of several artificial lift methods which were thought to defer liquid loading and mitigate kick-off issues such as Foam lift, Plunger lift, Beam Pump, ESP, Jet Pump and Gas lift (Concentric gas lift). The optimum gas Well de-liquification method has been identified based on the highest UR considering connected GIIP and inflow resistance A (Forchheimer equation Laminar flow). The outcome of the study indicated that a gas lift technology combined with well retubing was recommended as the optimum solution. The injected gas has reduced the density of the liquid resulting in reducing the static head at the tubing which increased the Well bore pressure allowing the Well to flow. A successful robust pilot which has been completed in two Wells and gave conclusive results. The surface development concept encompasses the development, with long term testing. The outstanding successful outcomes of the pilot succeeding in restoring Wells back with economic prolific production rates have led to expedite a full field implementation plan in three fields covering (33 Wells) in the next 5 years. These Wells have similar sub-surface and surface conditions. This paper will highlight the full story of the Gas lift technology implementation and describe in details the entire process starting from the Well candidate selection screening criteria, concept detailed design, critical success factors, project assurances and controls, Injection rate and operating parameters, facility capex, life time cycle and the result tested gas & condensate and water production. Also, the learning and challenges like halite accumulation effects will be shared along with the proven practical mitigation plan that ensured and sustained Well production resulting to significant project success of the technology.

Digitalization in Offloading for Mature Well Revival Optimization: Case Study of Peciko Gas Field

2020 ◽  
Author(s):  
D. Hidayat
Keyword(s):  
Dew Point ◽  
Liquid Loading ◽  
Gas Field ◽  
Common Solution ◽  
Point Pressure ◽  
Potential Alternative ◽  
Dew Point Pressure ◽  
Gas Volume ◽  
Analytical Tools ◽  
Stable Flow

Liquid loading is a common issue in the production of mature gas wells in lower pressure reservoirs that have gone below dew point pressure or have active water from an aquifer. With additional hydrostatic head inside the tubing column, the well’s energy will eventually become insufficient to lift all fluid to surface. A common solution to this issue is production of the well in an intermittent fashion with cyclic shut-in/build-up and placed-on-production (SIBU-POP). This method is oppressing liquid to depleted reservoirs and accumulating gas at the tubing’s upper section by gravity. Since this method only lifts a small volume of liquid and is more efficient in wells with multiple formations that produce commingled, offloading is a potential alternative to displace more liquid. Switching the well to atmospheric pressure will allow maximum drawdown to lift more liquid and enable stable flow for a certain period. By reaching stable flow, offloading will prolong the well’s producible lifetime and give greater incremental production than SIBU-POP activities. The Peciko gas field has been on production for approximately 25 years, offloading activities have become more frequent with time as the number of weak liquid-loaded wells increase. To obtain selective offload in mature gas field with long historical offload activities, a proper offloading database equipped with strong statistical and analytical tools is needed. An offloading database will utilize programming language to automatically store all the parameters prior, during, and post offloading activities to calculate instantaneous gain and recovered gas volume. Historical instantaneous gain and well parameters were then used for further statistical and engineering review to identify key wells and define offloading strategy. This digitization approach enables selective offload candidates in Peciko field and has increased instantaneous production of 4.5 MMscfd with 1.7 BSCF cumulative incremental in 2019. However, offloading does in some respect require greater coordination and integration than SIBU-POP programs, offloading activities require additional resources such as manpower, utility boat, etc. need to be planned and executed properly to maximize gain.

Fully integrated dynamic reservoir and well simulation model: Blacktip gas field case study

2018 ◽  
Vol 58 (1) ◽  
pp. 412
Author(s):  
Ryosuke Yokote ◽  
Mohammad Albarzanji ◽  
Yohan Suhardiman ◽  
Andrew Tran ◽  
Erni Dharma Putra ◽  
...  
Keyword(s):  
Simulation Model ◽  
Dynamic Model ◽  
Simulation Software ◽  
Integrated Modelling ◽  
Reservoir Pressure ◽  
Well Bore ◽  
Liquid Loading ◽  
Gas Field ◽  
Loading And Unloading ◽  
Start Ups

This paper describes an experience of integrating a dynamic reservoir simulation model with a dynamic well simulation model, resulting in an integrated dynamic model from the reservoir to the surface that enhances reservoir and well surveillance capability for the Blacktip gas field. Multiphase transient flow simulation is used to support daily well and pipeline operations for the project. The limitation of the standalone well model using a multiphase transient simulation software was its inability to reproduce pressure build up response during shut-ins, and pressure drawdown during start-ups. The fluid inflow from the reservoir to the well bore is modelled using the Inflow Performance Relationship (IPR) and accordingly the transient pressure behaviour near the well bore is not captured. This makes it difficult to estimate an accurate static reservoir pressure during shut-ins, as the predicted pressure instantaneously builds up to reservoir pressure specified in the IPR. The integrated dynamic model overcomes this limitation. The history matching of production intervals including shut-ins and start-ups using the integrated dynamic model along with high frequency data demonstrates that this integrated modelling approach can be used as a reliable surveillance tool to understand dynamic flow conditions from the reservoir to the surface, including liquid loading and unloading scenarios. The evolution of the history match and subsequent outcomes are discussed in the paper, along with the lessons learnt. Results of a liquid loading and unloading scenario for a gas well are also discussed in the paper.

Comprehensive Analysis of Production Loggings in Fuling Shale Gas Play in China

2021 ◽  
Author(s):  
Yaowen Liu ◽  
Wei Pang ◽  
Jincai Shen ◽  
Ying Mi
Keyword(s):  
Shale Gas ◽  
Mineral Content ◽  
Horizontal Wells ◽  
Organic Content ◽  
Gas Production ◽  
Liquid Loading ◽  
Comprehensive Overview ◽  
Gas Field ◽  
Well Trajectory ◽  
Positive Effect

Abstract Fuling shale gas field is one of the most successful shale gas play in China. Production logging is one of the vital technologies to evaluate the shale gas contribution in different stages and different clusters. Production logging has been conducted in over 40 wells and most of the operations are successful and good results have been observed. Some previous studies have unveiled one or several wells production logging results in Fuling shale gas play. But production logging results show huge difference between different wells. In order to get better understanding of the results, a comprehensive overview is carried out. The effect of lithology layers, TOC (total organic content), porosity, brittle mineral content, well trajectory is analyzed. Results show that the production logging result is consistent with the geology understanding, and fractures in the favorable layers make more gas contribution. Rate contribution shows positive correlation with TOC, the higher the TOC, the greater the rate contribution per stage. For wells with higher TOC, the rate contribution difference per stage is relatively smaller, but for wells with lower TOC, it shows huge rate contribution variation, fracture stages with TOC lower than 2% contribute very little, and there exist one or several dominant fractures which contributes most gas rate. Porosity and brittle minerals also show positive effect on rate contribution. The gas rate contribution per fracture stage increases with the increase of porosity and brittle minerals. The gas contribution of the front half lateral and that of latter half lateral are relatively close for the "upward" or horizontal wells. However, for the "downward" wells, the latter half lateral contribute much more gas than the front half lateral. It is believed that the liquid loading in the toe parts reduced the gas contribution in the front half lateral. The overview research is important to get a compressive understanding of production logging and different fractures’ contribution in shale gas production. It is also useful to guide the design of horizontal laterals and fractures scenarios design.

TUBINGLESS COMPLETIONS IN THE SURAT BASIN

1976 ◽  
Vol 16 (1) ◽  
pp. 107
Author(s):  
M. A. Delbaere
Keyword(s):  
Oil And Gas ◽  
Small Diameter ◽  
Development Projects ◽  
Well Bore ◽  
Gas Wells ◽  
Oil And Gas Development ◽  
Gas Field ◽  
Field Development ◽  
Reservoir Stimulation ◽  
Well Completion

Oilfield operators have always looked for ways of reducing the costs of oil and gas development projects and especially when investment costs were critical to project economics. Tubingless completions have evolved over the last 30 years in North America to fill the need for reduced investment costs particularly in the case of fields with either limited reserves or limited profitability.Tubingless completions basically utilise small diameter tubulars to function as both production casing and flowstring. The tubulars are cemented in the borehole, not to be removed or recovered until the field is depleted and/or the well abandoned. The technique is limited in application to those fields with no corrosion or wax or hydrate problems and with a limited requirement for reservoir stimulation and workovers. The greater the number of operations performed within the tubingless well bore the greater the risk of losing the well.The main benefits of tubingless completions are as follows:Reduction in development well completion costs.Marginally productive hydrocarbon zones can be completed and tested.Completion of individual gas zones of multi-pay wells within their own permanently segregated flowstrings at much lower capital and operating costs.The experience this far with Kincora gas field development wells indicates the tubingless completion method to be completely feasible for gas wells drilled in the Surat Basin and possibly in other areas of Australia.

Well Completion for Effective Deliquification of Natural Gas Wells

2011 ◽  
Vol 134 (1) ◽  
Author(s):  
John Yilin Wang
Keyword(s):  
Natural Gas ◽  
Operating Cost ◽  
Gas Production ◽  
Gas Wells ◽  
Liquid Loading ◽  
Gas Recovery ◽  
Well Completion ◽  
Reservoir Permeability ◽  
Gas Fields ◽  
Gas Lift

Liquid loading has been a problem in natural gas wells for several decades. With gas fields becoming mature and gas production rates dropping below the critical rate, deliquification becomes more and more critical for continuous productivity and profitability of gas wells. Current methods for solving liquid loading in the wellbore include plunger lift, velocity string, surfactant, foam, well cycling, pumps, compression, swabbing, and gas lift. All these methods are to optimize the lifting of liquid up to surface, which increases the operating cost, onshore, and offshore. However, the near-wellbore liquid loading is critical but not well understood. Through numerical reservoir simulation studies, effect of liquid loading on gas productivity and recovery has been quantified in two aspects: backup pressure and near-wellbore liquid blocking by considering variable reservoir permeability, reservoir pressure, formation thickness, liquid production rate, and geology. Based on the new knowledge, we have developed well completion methods for effective deliquifications. These lead to better field operations and increased ultimate gas recovery.

Optimising Offshore Gas Field Development with Large Well Bore Completion

2013 ◽  
Author(s):  
Ahmed Al-Baqawi ◽  
Amjad Ashri ◽  
Abdullah Al-Utaibi ◽  
Adnan Al-Kanan
Keyword(s):  
Well Bore ◽  
Gas Field ◽  
Field Development

The North Morecambe Field, Block 110/2a, East Irish Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 97-105 ◽  
Author(s):  
G. Cowan ◽  
T. Boycott-Brown
Keyword(s):  
Free Water ◽  
Irish Sea ◽  
Well Bore ◽  
High Angle ◽  
High Permeability ◽  
Gas Field ◽  
Free Zone ◽  
The North ◽  
Recoverable Reserves ◽  
Semi Arid

abstractThe North Morecambe Gas Field in the East Irish Sea Basin was discovered by well 110/2-3 in 1976 and contains ultimately recoverable reserves of over one TCF. THe structure is fault closed on three sides and dip closed to the north. Development was by ten conventionally drilled high angle deviated wells, from a not normally manned platform. Gas is exported through a dedicated pipeline to a new terminal at Barrow. The Triassic Sherwood Sandstone Group reservoir is composed of sandstones deposited in a semi-arid, fluvial and aeolian setting. Thin aeolian sandstones dominate flow into the well bore. Platy illite reduces the permeability by two to three orders of magnitude in the lower, illite affected zone of the reservoir, RFT measurements from the first development well proved that the free water level was 25 feet higher than expected, giving a maximum gas column of 975 feet. Re-mapping after drilling has shown that 56% of the GIIP is contained in the high permeability illite-free zone.

Determination of Optimum Rate in a Condensate Well with a Case of a Wellbore Liquid Loading

2021 ◽  
Author(s):  
Merit P. Ekeregbe
Keyword(s):  
Optimization Method ◽  
Dew Point ◽  
Quadratic Model ◽  
Liquid Loading ◽  
Optimum Rate ◽  
Well Production ◽  
Water Coning ◽  
Point Pressure ◽  
Water Cut ◽  
Bean Size

Abstract Condensate reservoirs are mostly pressure sensitive and keeping the pressure above the dew point pressure in the reservoir is critical to avoid condensate banking in the reservoir. If it occurs, production is highly inhibited and the well may ultimately quit on production under liquid loading. Fluid ratios are important in the management of condensate wells and most critical is the Gas Liquid Ratio (GLR). There is a certain GLR that below it, there will be a liquid loading in the wellbore that could quit the well. Each fluid rate goes with a GLR and the point where there is a reversal of the GLR or CGR trends may present a case of loading scenario and that is taken as the determination reference point. When a condensate well shows an improvement of water cut as the choke bean size is reduced does not necessarily signify a healthy situation and neither a one-point higher water cut with increase in choke bean size mean a water coning situation. When a liquid loading well is beaned up, there is early signs of water coning in the production data but this is just a wellbore production and the BS&W improves as the production rate is further increased. Further investigation is necessary to separate the challenge of water conning from the challenge of too low Gas rate which causes the loading of the liquids in the wellbore. That is the operating envelop to manage condensate well rates: rates too low with a possibility of a liquid loading and rates too high that depicts a case of water conning when water is close to the perforation. This band must be completely exploited to turn the production curve in the positive. This paper provides a strategy to recover a condensate well production with a challenge of liquid loading using a case study. The degree of the severity of the liquid loading can be represented using a power law model with the gradient being the level of severity of the loading. The production improvement is greater than nβ percent where n is the quadratic model number 2 and β is the product of the graphical and Lagrangian-Quadratic alpha parameters. The optimum rate can be determined using the Lagrange Multiplier optimization method to effectively extend the production life of the well.

Remote-Controlled Automated Foam Injection: A Digital Solution to Liquid Loading in a China Unconventional Gas Development

2021 ◽  
Author(s):  
Jiang Wei Bo ◽  
Beryl Audrey ◽  
Uzezi Orivri ◽  
Nian Xi Wang ◽  
Xiang Yang Qiao ◽  
...  
Keyword(s):  
Remote Control ◽  
Continuous Production ◽  
Weather Conditions ◽  
Gas Production ◽  
Liquid Loading ◽  
Gas Field ◽  
Field Development ◽  
Operational Risks ◽  
Tight Gas Reservoir ◽  
Unconventional Gas Development

Abstract Gas field C is an unconventional tight gas reservoir located in the central of China which has prominent characteristics, including thin formation, low permeability and poor reservoir connectivity which significantly impact on the field development. Horizontal wells multistage hydraulic fracturing has been proven to be an effective technique to recover the hydrocarbons from this gas field. However, with continuous production overtime, reservoir pressure declines which results in a decrease in gas production rate below the critical gas velocity, leading to accumulation of liquid in the wellbore (liquid loading), which further results in back pressure and damage to the formation. Currently, gas field C loses up to 1500 mmscf/year in gas production and associated revenue due to liquid loading. Some other factors which hinders effective deliquification of the gas wells include remote well pad locations, poor road conditions during harsh weather conditions, friction with local communities, limited manpower to daily effectively analyze over 200 wells for liquid loading diagnostics and operational risks during well intervention. To tackle these challenges, a new versatile intelligent dosing technology has been piloted to reduce liquid loading. This remote-control dosing unit is located at the well pad and is equipped with automatic valves that can dispense two different chemicals (soap and methanol) in one unit. A key new feature of this system is the ability to receive and implement instructions that optimizes the dosing rate and frequency. This remote-control functionality eliminates on-site operator intervention and HSE risks especially in winter when the well pads could be inaccessible with poor road conditions.

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