Improving Production Performance by Coupling Power Water Injection and Gas Lift in Pressure-Depleted Gas-Cap Reservoirs

2014 ◽  
Author(s):  
Idowu Odumboni ◽  
Subhayu Basu
Keyword(s):  
Water Injection ◽  
Production Performance ◽  
Gas Lift

Analytical Rate-Transient Analysis and Production Performance of Waterflooded Fields with Delayed Injection Support

2021 ◽  
pp. 1-23
Author(s):  
Daniel O'Reilly ◽  
Manouchehr Haghighi ◽  
Mohammad Sayyafzadeh ◽  
Matthew Flett
Keyword(s):  
Steady State ◽  
Transient Analysis ◽  
Water Injection ◽  
Data Interpretation ◽  
Production Performance ◽  
Production Data ◽  
Reservoir Properties ◽  
Two Phase ◽  
Production Forecasting ◽  
Rate Transient Analysis

Summary An approach to the analysis of production data from waterflooded oil fields is proposed in this paper. The method builds on the established techniques of rate-transient analysis (RTA) and extends the analysis period to include the transient- and steady-state effects caused by a water-injection well. This includes the initial rate transient during primary production, the depletion period of boundary-dominated flow (BDF), a transient period after injection starts and diffuses across the reservoir, and the steady-state production that follows. RTA will be applied to immiscible displacement using a graph that can be used to ascertain reservoir properties and evaluate performance aspects of the waterflood. The developed solutions can also be used for accurate and rapid forecasting of all production transience and boundary-dominated behavior at all stages of field life. Rigorous solutions are derived for the transient unit mobility displacement of a reservoir fluid, and for both constant-rate-injection and constant-pressure-injection after a period of reservoir depletion. A simple treatment of two-phase flow is given to extend this to the water/oil-displacement problem. The solutions are analytical and are validated using reservoir simulation and applied to field cases. Individual wells or total fields can be studied with this technique; several examples of both will be given. Practical cases are given for use of the new theory. The equations can be applied to production-data interpretation, production forecasting, injection-water allocation, and for the diagnosis of waterflood-performanceproblems. Correction Note: The y-axis of Fig. 8d was corrected to "Dimensionless Decline Rate Integral, qDdi". No other content was changed.

Artificial Lift Optimization for Shallow Carbonate Magwa and Ostracod Formations with Massive Propped Fractures

2021 ◽  
Author(s):  
Nasser AlAskari ◽  
Muhamad Zaki ◽  
Ahmed AlJanahi ◽  
Hamed AlGhadhban ◽  
Eyad Ali ◽  
...  
Keyword(s):  
Production Performance ◽  
Shallow Depth ◽  
Production Rates ◽  
Field Development ◽  
Artificial Lift ◽  
Geological Conditions ◽  
Fracture Fluid ◽  
Reservoir Potential ◽  
Gas Lift

Abstract Objectives/Scope: The Magwa and Ostracod formations are tight and highly fractured carbonate reservoirs. At shallow depth (1600-1800 ft) and low stresses, wide, long and conductive propped fracture has proven to be the most effective stimulation technique for production enhancement. However, optimizing flow of the medium viscosity oil (17-27 API gravity) was a challenge both at initial phase (fracture fluid recovery and proppant flowback risks) and long-term (depletion, increasing water cut, emulsion tendency). Methods, Procedures, Process: Historically, due to shallow depth, low reservoir pressure and low GOR, the optimum artificial lift method for the wells completed in the Magwa and Ostracod reservoirs was always sucker-rod pumps (SRP) with more than 300 wells completed to date. In 2019 a pilot re-development project was initiated to unlock reservoir potential and enhance productivity by introducing a massive high-volume propped fracturing stimulation that increased production rates by several folds. Consequently, initial production rates and drawdown had to be modelled to ensure proppant pack stability. Long-term artificial lift (AL) design was optimized using developed workflow based on reservoir modelling, available post-fracturing well testing data and production history match. Results, Observations, Conclusions: Initial production results, in 16 vertical and slanted wells, were encouraging with an average 90 days production 4 to 8 times higher than of existing wells. However, the initial high gas volume and pressure is not favourable for SRP. In order to manage this, flexible AL approach was taken. Gas lift was preferred in the beginning and once the production falls below pre-defined PI and GOR, a conversion to SRP was done. Gas lift proved advantageous in handling solids such as residual proppant and in making sure that the well is free of solids before installing the pump. Continuous gas lift regime adjustments were taken to maximize drawdown. Periodical FBHP surveys were performed to calibrate the single well model for nodal analysis. However, there limitations were present in terms of maximizing the drawdown on one side and the high potential of forming GL induced emulsion on the other side. Horizontal wells with multi-stage fracturing are common field development method for such tight formations. However, in geological conditions of shallow and low temperature environment it represented a significant challenge to achieve fast and sufficient fracture fluid recovery by volume from multiple fractures without deteriorating the proppant pack stability. This paper outlines local solutions and a tailored workflow that were taken to optimize the production performance and give the brown field a second chance. Novel/Additive Information: Overcoming the different production challenges through AL is one of the keys to unlock the reservoir potential for full field re-development. The Magwa and Ostracod formations are unique for stimulation applications for shallow depth and range of reservoirs and fracture related uncertainties. An agile and flexible approach to AL allowed achieving the full technical potential of the wells and converted the project to a field development phase. The lessons learnt and resulting workflow demonstrate significant value in growing AL projects in tight and shallow formations globally.

A Simplified and Efficient Method for Water Flooding Production Index Calculations in Low Permeable Fractured Reservoir

2019 ◽  
Vol 141 (11) ◽  
Author(s):  
Shun Liu ◽  
Liming Zhang ◽  
Kai Zhang ◽  
Jianren Zhou ◽  
Heng He ◽  
...  
Keyword(s):  
Fractured Reservoirs ◽  
Water Injection ◽  
Cross Flow ◽  
Production Performance ◽  
Water Flooding ◽  
Simplified Model ◽  
Single Fracture ◽  
Fractured Reservoir ◽  
Production Index ◽  
Future Production

Presently, predicting the production performance of fractured reservoirs is often challenging because of the following two factors: one factor such as complicatedly connected and random distribution nature of the fractures and the other factor includes the limitations of the understanding of reservoir geology, deficient fracture-related research, and defective simulators. To overcome the difficulties of simulating and predicting fractured reservoir under complex circumstances of cross flow, a simplified model, which assumes cross flow only exists in the oil phase segment, is constructed. In the model, the pressure distribution of a single fracture can be described by solving an analytical mathematical model. In addition, due to research and field experience which indicate that cross flow also exists in the mixed-phase segment after water injection, the simplified model is modified to consider cross flow in the whole phase. The model constructed here is applicable for fractured reservoirs especially for a low-permeability fracture reservoir, and it moderately predicts future production index. By using iterative methods, the solution to the model can be feasibly obtained and related production performance index formulas can be derived explicitly. A case study was performed to test the model, and the results prove that it is good.

The Emerald Field, Blocks 2/10a, 2/15a, 3/11b, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 111-116 ◽  
Author(s):  
D. M. Stewart ◽  
A. J. G. Faulkner
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Maximum Flow ◽  
Oil Field ◽  
Injection Wells ◽  
Initial Development ◽  
Flexible Risers ◽  
Northern North Sea ◽  
The Uk ◽  
Gas Lift

AbstractThe Emerald Oil Field lies in Blocks 2/10a, 2/15a and 3/1 lb in the UK sector of the northern North Sea. The field is located on the 'Transitional Shelf, an area on the western flank of the Viking Graben, downfaulted from the East Shetland Platform. The first well was drilled on the structure in 1978. Subsequently, a further seven wells have been drilled to delineate the field.The Emerald Field is an elongate dip and fault closed structure subparallel to the local NW-SE regional structural trend. the 'Emerald Sandstone' forms the main reservoir of the field and comprises a homogeneous transgressive unit of Callovian to Bathonian age, undelain by tilted Precambrian and Devonian Basement Horst blocks. Sealing is provided by siltstones and shales of the overlying Healther and Kimmeridge Clay Formations. The reservoir lies at depths between 5150-5600 ft, and wells drilled to date have encountered pay thicknesses of 42-74 ft. Where the sandstone is hydrocarbon bearing, it has a 100% net/ gross ratio. Porosities average 28% and permeabilities lie in the range 0-1 to 1.3 darcies. Wireline and test data indicate that the field contains a continouous oil column of 200 ft. Three distinct structural culminations exist on and adjacent to the field, which give rise to three separate gas caps, centred around wells 2/10a-4, 2/10a-7 and 2/10a-6 The maximum flow rate achieved from the reservoir to date is 6822 BOPD of 24° API oil with a GOR of 300 SCF/STBBL. In-place hydrocarbons are estimated to be 216 MMBBL of oil and 61 BCF of gas, with an estimated 43 MMBBL of oil recoverable by the initial development plan. initial development drilling began in Spring 1989 and the development scheme will use a floating production system. Production to the facility, via flexible risers, is from seven pre-drilled deviated wells with gas lift. An additional four pre-drilled water injection wells will provide reservoir pressure support.

scholarly journals Geysers Valley CO2 Cycling Geological Engine (Kamchatka, Russia)

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-16 ◽  
Author(s):  
A. Kiryukhin ◽  
V. Sugrobov ◽  
E. Sonnenthal
Keyword(s):  
Water Discharge ◽  
Water Injection ◽  
Geothermal Reservoir ◽  
Chemical Components ◽  
Natural State ◽  
Water Influx ◽  
Chemical History ◽  
Valley Of Geysers ◽  
Giant Landslide ◽  
Gas Lift

1941–2017 period of the Valley of Geysers monitoring (Kamchatka, Kronotsky Reserve) reveals a very dynamic geyser behavior under natural state conditions: significant changes of IBE (interval between eruptions) and power of eruptions, chloride and other chemical components, and preeruption bottom temperature. Nevertheless, the total deep thermal water discharge remains relatively stable; thus all of the changes are caused by redistribution of the thermal discharge due to giant landslide of June 3, 2007, mudflow of Jan. 3, 2014, and other events of geothermal caprock erosion and water injection into the geothermal reservoir. In some cases, water chemistry and isotope data point to local meteoric water influx into the geothermal reservoir and geysers conduits. TOUGHREACT V.3 modeling of Velikan geyser chemical history confirms 20% dilution of deep recharge water and CO2 components after 2014. Temperature logging in geysers Velikan (1994, 2007, 2015, 2016, and 2017) and Bolshoy (2015, 2016, and 2017) conduits shows preeruption temperatures below boiling at corresponding hydrostatic pressure, which means partial pressure of CO2 creates gas-lift upflow conditions in geyser conduits. Velikan geyser IBE history explained in terms of gradual CO2 recharge decline (1941–2013), followed by CO2 recharge significant dilution after the mudflow of Jan. 3, 2014, also reshaped geyser conduit and diminished its power.

scholarly journals A New Methodology for the Multilayer Tight Oil Reservoir Water Injection Efficiency Evaluation and Real-Time Optimization

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-17
Author(s):  
Lin Cao ◽  
Jianlong Xiu ◽  
Hongjie Cheng ◽  
Hui Wang ◽  
Shujian Xie ◽  
...  
Keyword(s):  
Water Injection ◽  
Sedimentary Facies ◽  
Production Performance ◽  
Water Flooding ◽  
Tight Oil ◽  
Oil Reservoir ◽  
Reservoir Water ◽  
Injection Efficiency ◽  
Tight Oil Reservoir ◽  
Channel Bar

It is important to determine the reasonable injection and production rates in the development of multilayer tight oil reservoir with water flooding treatment. Based on the INSIM (interconnection-based numeric simulation model), a connected network model, a new method is designed to evaluate the water injection efficiency of different layers in water flooding reservoirs and to optimize the injection-production system to produce more oil. Based on the types of sedimentary facies and corresponding injection-production data, the interwell connections are divided into four major categories (middle channel, channel edge, middle channel bar, and channel bar edge) and twelve subclasses. This classification standard of interwell connections could help to significantly improve the accuracy of judging the dominant flow path without constructing a complicated geological model. The interaction of interwells such as injection-production correlation and water injection efficiency could be revealed by simulating the production performance and computing the layer dividing coefficient and well dividing coefficient. A numerical example is used to validate this method by comparing results from FrontSim and this method, and the computational efficiency of this method is several dozen times faster than that of the traditional numerical simulation. This method is applied to quickly optimize the production schedule of a tight oil reservoir with the water flooding treatment, that is, the water injection rate of multilayer reservoirs could be optimized subtly by the injection efficiency of different layers, and the target of producing more oil with lower water cut could be achieved.

Cost Reduction Strategies in Workover operations in the Face of Low Oil Price: The Agbada Workover Project

2016 ◽  
Author(s):  
Joy Eze ◽  
Oluwarotimi Onakomaiya ◽  
Ademola Ogunrinde ◽  
Olusegun Adegboyega ◽  
James Wopara ◽  
...  
Keyword(s):  
Cost Reduction ◽  
Operating Cost ◽  
Cost Savings ◽  
Oil Price ◽  
Production Performance ◽  
Program Optimization ◽  
Associated Gas ◽  
Early Return ◽  
Reduction Strategies ◽  
Gas Lift

ABSTRACT The current low oil price has resulted in several continuous improvement drives particularly focused on capital efficiency. With over 60 producing oil fields and approximately 700 producing wells, some of which date back to the 60s, work over operations in Shell Petroleum Development Company (SPDC) is imperative. Having completed over twenty (20) Work Over operations in the last six years in SPDC, the importance of Work Over operations as a means to sustain production especially for relatively old, dysfunctional or non-compliant wells and keep the production funnel full at a relatively lower cost compared to new drills is more evident. Work over operations, defined as the repair and/or stimulation of existing wells in order to improve production performance presents the opportunity to maximize short term gains from already existing facilities. The objective of the workover operations on Agbada ABC and XYZ was to restore well integrity with the installation of sub surface safety valves and gas lift mandrels instead of insert orifice while assuring the development of oil and associated gas. The insert orifice had been installed on both wells to enable gas lift operations from the Agbada Associated Gas Gathering (AGG) plant since they were unable to sustain natural flow. However, due to epileptic AGG, both wells quit frequently requiring nitrogen lift with an average Non-Productive Times (NPT) of 6 months per year while Agbada XYZ was put on cyclic production and had been a pressure build-up well with at least two weeks down time per month. The workover operation was therefore proposed to replace the existing (punched) tubing, install proper gas lift mandrels for optimum performance, reduce well operating cost arising from AGG outage and/or compressor failure and restore production in the reservoir. This paper aims to discuss the cost reduction strategies such as collaboration, re-use, program optimization and operational efficiency applied in driving down Non-Productive Times (NPT) in the efficient delivery of these workover operations which resulted in <6% NPT, >30% time savings, ca. 40% cost savings and early return of wells to production.

Production Performance Analysis of Western Siberia Mature Waterflood with Prime Diagnostic Metrics

2021 ◽  
Author(s):  
Arthur Aslanyan ◽  
Andrey Margarit ◽  
Arkadiy Popov ◽  
Ivan Zhdanov ◽  
Evgeniy Pakhomov ◽  
...  
Keyword(s):  
Cross Sections ◽  
Western Siberia ◽  
Performance Metrics ◽  
Water Injection ◽  
Production Performance ◽  
Practical Case ◽  
Flow Profile ◽  
Water Production ◽  
Production Analysis ◽  
Conventional Production

Abstract The paper shares a practical case of production analysis of mature field in Western Siberia with a large stock of wells (> 1,000) and ongoing waterflood project. The main production complications of this field are the thief water production, thief water injection and non-uniform vertical sweep profile. The objective of the study was to analyse the 30-year history of development using conventional production and surveillance data, identify the suspects of thief water production and thief water injection and check the uniformity of the vertical flow profile. Performing such an analysis on well-by-well basis is a big challenge and requires a systematic approach and substantial automation. The majority of conventional diagnostic metrics fail to identify the origin of production complications. The choice was made in favour of production analysis workflow based on PRIME metrics, which automatically generates numerous conventional production performance metrics (including the reallocated production maps and cross-sections) and additionally generates advanced metrics based on automated 3D micro-modelling. This allowed to zoom on the wells with potential complications and understand their production/recovery potential. The PRIME analysis has also helped to identify the wells and areas which potentially may hold recoverable reserves and may benefit from additional well and cross-well surveillance.

A New Methodology of Production Performance Prediction for Strong Edge-Water Reservoir

2020 ◽  
Vol 143 (8) ◽  
Author(s):  
Angang Zhang ◽  
Zifei Fan ◽  
Lun Zhao ◽  
Jincai Wang ◽  
Heng Song
Keyword(s):  
Performance Prediction ◽  
Water Saturation ◽  
Water Injection ◽  
Material Balance ◽  
Water Reservoir ◽  
Production Performance ◽  
Water Flooding ◽  
Gas Oil ◽  
Permeability Model ◽  
Water Influx

Abstract Material balance is a basic principle in reservoir engineering, which is still used as a quick and easy analytical tool for reservoir evaluation. In this article, a new methodology of production performance prediction for water-flooding reservoir was proposed based on the material balance principle, which considers the water saturation change caused by water injection and natural water influx, and its effect on transient gas–oil ratio. Among them, the cumulative water production was calculated based on Tong’s water-driver performance curve; the cumulative water influx was obtained by the Fetkovitch method; the transient gas–oil ratio can be acquired by Darcy’s law and Baker’s relative permeability model. Comparisons have been made between the new methodology and commercial reservoir simulator for two different reservoirs. The results show that there is good similarity between these two tools, which verifies the correctness of the new methodology.

Gas Lift Optimization of an Oil Field in Malaysia

2014 ◽  
Vol 974 ◽  
pp. 367-372
Author(s):  
Nurul Aimi Ghazali ◽  
T.A.T. Mohd ◽  
N. Alias ◽  
E. Yahya ◽  
M.Z. Shahruddin ◽  
...  
Keyword(s):  
Hydrostatic Pressure ◽  
Gas Injection ◽  
Oil Field ◽  
Production Performance ◽  
Base Case ◽  
External Energy ◽  
Hole Pressure ◽  
Bottom Hole Pressure ◽  
Bottom Hole ◽  
Gas Lift

Gas lift is an artificial lift method which is commonly used in offshore operation with sufficient gas sources as it consumes minimum space on the platform. Gas lift operates by injecting a high pressure gas down through the tubing casing annulus of a well and the injected gas enters the tubing through a gas lift valve installed on the tubing. Gas lift increases production by two means, density reduction of oil column inside the tubing so that the flowing bottom-hole pressure which is affected by the hydrostatic pressure of the fluid column is reduced and by providing external energy to the oil as the gas expends.Reducing the bottom-hole pressure will improve the drawdown of the well. A production well is modelled by using a production modelling program, Integrated Production Modeling (IPM) Prosper to analyze the production performance at various conditions. A base case model is developed from the production data of an actual oil field to simulate the performance of the actual well without gas lift system. Later, the gas lift is added to the model and the performance was compared with the base case model. The gas parameter was also studied to determine the optimum injection gas condition for maximum oil production. The gas injected at 1490m can be achieved by injecting the gas with 1200 psi, l300 psi or 1400 psi. However, the optimum gas injection pressure was determined to be at 1400 psi as the design shows that the required unloading stage is the least. The optimum gas injection rate was determined at 5 MMscf/d with the estimated net revenue is the highest. For injection gas gravity, the lighter gas was determined to be the optimum selection since it gives significant reduction of FBHP (Flowing Bottom Hole Pressure) with less hydrostatic pressure inside the tubing column.

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