Novel Methodology to Estimate Reservoir Pressure and Productivity Index in Unconventional and Conventional Reservoirs Using Production Data

2016 ◽  
Author(s):  
Bobby Poe ◽  
Gottumukkala Varma
Keyword(s):  
Productivity Index ◽  
Production Data ◽  
Reservoir Pressure

GAS FIELD DELIVERABILITY PREDICTIONS AND DEVELOPMENT ECONOMICS

1967 ◽  
Vol 7 (1) ◽  
pp. 115
Author(s):  
A. N. Edgington ◽  
N. E. Cleland
Keyword(s):  
Material Balance ◽  
Production Data ◽  
Reservoir Pressure ◽  
Computer Programme ◽  
Gas Field ◽  
Open Flow ◽  
Bottom Hole ◽  
Present Worth ◽  
Net Revenue ◽  
Economic Criteria

Forecast of well deliverabilities are an absolute necessity for the realistic planning of the production, transmission and reticulation of natural gas.Gas well deliverability is a function of both natural and artificial limitations and both must be considered in a deliverability forecast.The direct prediction of the decline in wellhead deliverability during the life of a well is a relatively recent development and uses a wellhead relationship analogous to the formation open flow formula. This relationship, combined with the material balance pressure decline equation and the formula relating bottom-hole to wellhead conditions, forms the basis for deliverability forecasts.Compression is added to provide maximum well deliverability and wells may be drilled during the life of a project to maintain deliverability. New wells should meet certain minimum economic criteria before they can be justified. Suggested Criteria are:The net revenue to be earned by the new well must be a pre-selected multiple of the investment required,The present worth of the net revenue discounted at a pre-selected rate must be greater than the investment required.A computer programme has been written to carry out the tedious, repetitive and time-consuming calculations which are necessary for the solution to the problem of deliverability forecasting. This programme calculates the annual production and availability of pipeline gas as well as the number of welJs required to deplete the reserves efficiently. The average reservoir pressure and shut-in and flowing wellhead pressures are forecast and the amount of compression required is calculated. The computer output includes all the production data required for a complete economic analysis of a project involving the depletion of a gas field.

scholarly journals Dynamic Material Balance Method for Estimating Gas in Place of Abnormally High-Pressure Gas Reservoirs

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Lixia Zhang ◽  
Yingxu He ◽  
Chunqiu Guo ◽  
Yang Yu
Keyword(s):  
High Pressure ◽  
Material Balance ◽  
Balance Method ◽  
Production Data ◽  
Reservoir Pressure ◽  
Material Balance Equation ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Material Balance Method ◽  
The Relationship

Abstract Determination of gas in place (GIP) is among the hotspot issues in the field of oil/gas reservoir engineering. The conventional material balance method and other relevant approaches have found widespread application in estimating GIP of a gas reservoir or well-controlled gas reserves, but they are normally not cost-effective. To calculate GIP of abnormally pressured gas reservoirs economically and accurately, this paper deduces an iteration method for GIP estimation from production data, taking into consideration the pore shrinkage of reservoir rock and the volume expansion of irreducible water, and presents a strategy for selecting an initial iteration value of GIP. The approach, termed DMBM-APGR (dynamic material balance method for abnormally pressured gas reservoirs) here, is based on two equations: dynamic material balance equation and static material balance equation for overpressured gas reservoirs. The former delineates the relationship between the quasipressure at bottomhole pressure and the one at average reservoir pressure, and the latter reflects the relationship between average reservoir pressure and cumulative gas production, both of which are rigidly demonstrated in the paper using the basic theory of gas flow through porous media and material balance principle. The method proves effective with several numerical cases under various production schedules and a field case under a variable rate/variable pressure schedule, and the calculation error of GIP does not go beyond 5% provided that the production data are credible. DMBM-APGR goes for gas reservoirs with abnormally high pressure as well as those with normal pressure in virtue of its strict theoretical foundation, which not only considers the compressibilities of rock and bound water, but also reckons with the changes in production rate and variations of gas properties as functions of pressure. The method may serve as a valuable and reliable tool in determining gas reserves.

scholarly journals Impact of Hydraulic Fracturing on Productivity of Gas Condensate Wells

2020 ◽  
Vol 8 (6) ◽  
pp. 1202-1208
Keyword(s):  
Hydraulic Fracture ◽  
Gas Condensate ◽  
Dew Point ◽  
Darcy Flow ◽  
Productivity Index ◽  
Reservoir Pressure ◽  
Pressure Drops ◽  
Compositional Simulator ◽  
Point Pressure ◽  
Dew Point Pressure

Having an increase in the discovery of gas reservoirs all over the world, the most common problem related to gas condensate wells while producing below dew point condition is condensate banking. As the bottom hole pressure drops below the dew point, the liquid starts to exist and condensate begins to accumulate. Relative permeability of gas will be reduced as well as the well productivity will start to decline. The effect of applying a hydraulic fracture to gas condensate wells is the main objective of this paper. A compositional simulator is utilized to investigate the physical modifications that could happen to gas and condensate during the production life of an arbitrary well. Performing a good designed hydraulic fracture to a gas condensate well typically enhances the production of such well. This increase depends basically on certain factors such as non-Darcy flow, capillary number and capillary pressure. Non-Darcy flow has a dominant impact on gas and condensate productivity index after performing a hydraulic fracture as the simulator indicates. The enhancement of gas and condensate production can be obtained for gas condensate reservoirs in which the reservoir pressure is above or around the dew point pressure to have a margin for the pressure to decline with time and also eliminate the probability of forming condensate in the reservoir. On the other hand if the reservoir pressure is below the dew point pressure, there will be definitely a condensate in the reservoir and a specific design for the hydraulic fracture is a must to get the required enhancement in the production.

Fit-For-Purpose History Matching Approach for A Low-Quality Reservoir Under Waterflood: Integration of Uncertain Production Allocation

2020 ◽  
Author(s):  
M. Syafwan
Keyword(s):  
History Matching ◽  
Production Data ◽  
Reservoir Pressure ◽  
Reservoir Model ◽  
Production Forecast ◽  
Oil Saturation ◽  
Production Allocation ◽  
Fluid Production ◽  
Fit For Purpose ◽  
Well Level

This paper presents a fit-for-purpose approach to mitigate zonal production data allocation uncertainty during history matching of a reservoir simulation model due to limited production logging data. To avoid propagating perforation/production zone allocation uncertainty at commingled wells into the history matched reservoir model, only well-level production data from historical periods when production was from a single zone were used to calibrate reservoir properties that determine initial volumetric. Then, during periods of the history with commingled production, average reservoir pressure measurements were integrated into the model to allocate fluid production to the target reservoir. Last, the periods constrained by dedicated well-level fluid production and average reservoir pressure were merged over the forty-eight-year history to construct a single history matched reservoir model in preparation for waterflood performance forecasting. This innovative history matching approach, which mitigates the impacts of production allocation uncertainty by using different intervals of the historical data to calibrate model saturations and model pressures, has provided a new interpretation of OOIP and current recovery factor, as well as drive mechanisms including aquifer strength and capillary pressure. Fluid allocation from the target reservoir in the history matched model is 85% lower than previously estimated. The history matched model was used as a quantitative forecasting and optimization tool to expand the recent waterflood with improved production forecast reliability. The remaining mobile oil saturation map and streamline-based waterflood diagnostics have improved understanding of injector-producer connectivity and swept pore volumes, e.g., current swept volumes are minor and well-centric with limited indication of breakthrough at adjacent producers resulting in high remaining mobile oil saturation. Accordingly, the history matched model provides a foundation to select new injection points, determine dedicated producer locations and support optimized injection strategies to improve recovery.

First Successful Proppant Frac in a Water Injection Field Strategy, West Qurna-1, South Iraq

2022 ◽  
Author(s):  
Erfan Mustafa Al lawe ◽  
Adnan Humaidan ◽  
Afolabi Amodu ◽  
Mike Parker ◽  
Oscar Alvarado ◽  
...  
Keyword(s):  
Water Injection ◽  
Injection Rate ◽  
Fracture Model ◽  
Productivity Index ◽  
Base Line ◽  
Reservoir Pressure ◽  
Injection Strategy ◽  
Injection Test ◽  
Step Rate ◽  
Step Down

Abstract Zubair formation in West Qurna field, is one of the largest prolific reservoirs comprising of oil bearing sandstone layers interbedded with shale sequences. An average productivity index of 6 STB/D/psi is observed without any types of stimulation treatment. As the reservoir pressure declines from production, a peripheral water injection strategy was planned in both flanks of the reservoir to enhance the existing wells production deliverability. The peripheral injection program was initiated by drilling several injectors in the west flank. Well A1 was the first injector drilled and its reservoir pressure indicated good communication with the up-dip production wells. An injection test was conducted, revealing an estimated injectivity index of 0.06 STB//D/psi. Candidate well was then re-perforated and stimulated with HF/HCl mud acid, however no significant improvement in injectivity was observed due to the complex reservoir mineralogy and heterogeneity associated to the different targeted layers. An extended high-pressure injection test was performed achieving an injectivity index of 0.29 STB/D/psi at 4500 psi. As this performance was sub-optimal, a proppant fracture was proposed to achieve an optimal injection rate. A reservoir-centric fracture model was built, using the petrophysical and geo-mechanical properties from the Zubair formation, with the objective of optimizing the perforation cluster, fracture placement and injectivity performance. A wellhead isolation tool was utilized as wellhead rating was not able to withstand the fracture model surface pressure; downhole gauges were also installed to provide an accurate analysis of the pressure trends. The job commenced with a brine injection test to determine the base-line injectivity profile. The tubing volume was then displaced with a linear gel to perform a step-rate / step-down test. The analysis of the step-rate test revealed the fracture extension pressure, which was set as the maximum allowable injection pressure when the well is put on continuous injection. The step-down test showed significant near wellbore tortuosity with negligible perforation friction. A fracture fluid calibration test was then performed to validate the integrated model leak-off profile, fracture gradient and young’s modulus; via a coupled pressure fall-off and temperature log analysis. Based on the fluid efficiency, the pad volume was adjusted to achieve a tip screen-out. The job was successfully pumped and tip screen-out was achieved after pumping over ~90% of the planned proppant volume. A 7 days post-frac extended injection test was then conducted, achieving an injection rate of 12.5 KBWD at 1300 psi with an injectivity index of 4.2 STB/D/psi. These results proved that the implementation of a reservoir-centric Proppant Fracture treatment, can drastically improve the water injection strategy and field deliverability performance even in good quality rock formations. This first integrated fracture model and water injection field strategy, represents a building platform for further field development optimization plans in Southern Iraq.

The Use of Combined Static- and Dynamic-Material-Balance Methods With Real-Time Surveillance Data in Volumetric Gas Reservoirs

2012 ◽  
Vol 15 (03) ◽  
pp. 351-360 ◽  
Author(s):  
D.. Ismadi ◽  
C.S.. S. Kabir ◽  
A.R.. R. Hasan
Keyword(s):  
Real Time ◽  
Management Practice ◽  
Material Balance ◽  
Surveillance Data ◽  
Productivity Index ◽  
Reservoir Engineering ◽  
Reservoir Pressure ◽  
Layered Systems ◽  
Gas Reservoirs ◽  
Systematic Procedure

Summary Estimating in-place volume associated with each well, leading to estimation of total reservoir in-place volume, is the cornerstone to any reservoir-management practice. Yet, conventional methods do not always lend themselves to routine applications, particularly when used in singular fashion. However, combining these methods on the same plot has considerable merit in that they converge to the same solution when material-balance (MB) -derived averagereservoir pressure is used in a volumetric system. This study presents a systematic procedure for estimating the gas-initially-in-place (GIIP) volume when real-time surveillance data of pressure, rate, and temperature are available at the wellhead. Specifically, we show that log-log diagnosis, followed by combined static- and dynamic-MB analysis and transient-productivity-index (PI) analysis, leads to consistent solutions. Thermodynamic behavior of fluids is also explored to ensure that converted pressures at the bottomhole and measured rates have consistency and accuracy for reservoir-engineering calculations. Layered systems were selected for this study because they represent most situations. Two synthetic cases probed issues pertaining to average-reservoir-pressure computation with the pseudosteady-state (PSS) approach, and two field examples validated the approach presented here.

An Integrated Model for History Matching and Predicting Reservoir Performance of Gas/Condensate Wells

2013 ◽  
Vol 16 (04) ◽  
pp. 412-422
Author(s):  
A.M.. M. Farid ◽  
Ahmed H. El-Banbi ◽  
A.A.. A. Abdelwaly
Keyword(s):  
History Matching ◽  
Material Balance ◽  
Integrated Model ◽  
Gas Condensate ◽  
Production Performance ◽  
Productivity Index ◽  
Production Data ◽  
Fluid Composition ◽  
Two Phase ◽  
Reservoir Simulator

Summary The depletion performance of gas/condensate reservoirs is highly influenced by changes in fluid composition below the dewpoint. The long-term prediction of condensate/gas reservoir behavior is therefore difficult because of the complexity of both composition variation and two-phase-flow effects. In this paper, an integrated model was developed to simulate gas-condensate reservoir/well behavior. The model couples the compositional material balance or the generalized material-balance equations for reservoir behavior, the two-phase pseudo integral pressure for near-wellbore behavior, and outflow correlations for wellbore behavior. An optimization algorithm was also used with the integrated model so it can be used in history-matching mode to estimate original gas in place (OGIP), original oil in place (OOIP), and productivity-index (PI) parameters for gas/condensate wells. The model also can be used to predict the production performance for variable tubinghead pressure (THP) and variable production rate. The model runs fast and requires minimal input. The developed model was validated by use of different simulation cases generated with a commercial compositional reservoir simulator for a variety of reservoir and well conditions. The results show a good agreement between the simulation cases and the integrated model. After validating the integrated model against the simulated cases, the model was used to analyze production data for a rich-gas/condensate field (initial condensate/gas ratio of 180 bbl/ MMscf). THP data for four wells were used along with basic reservoir and production data to obtain original fluids in place and PIs of the wells. The estimated parameters were then used to forecast the gas and condensate production above and below the dewpoint. The model is also capable of predicting reservoir pressure, bottomhole flowing pressure, and THP and can account for completion changes when they occur.

Track Fractured Well Inflow Performance Using Historic Production Logging and Surface Well Performance Data in Sultanate of Oman

2022 ◽  
Author(s):  
Cornelis Adrianus Veeken ◽  
Yousuf Busaidi ◽  
Amira Hajri ◽  
Ahmed Mohammed Hegazy ◽  
Hamyar Riyami ◽  
...  
Keyword(s):  
Production Data ◽  
Hydraulic Fractures ◽  
Reservoir Pressure ◽  
Sultanate Of Oman ◽  
Well Performance ◽  
Pressure Depletion ◽  
Stress Dependent ◽  
Inflow Performance ◽  
The Impact ◽  
Surface Production

Abstract PDO operates about 200 deep gas wells in the X field in the Sultanate of Oman, producing commingled from the Barik gas-condensate and Miqrat lean gas reservoir completed by multiple hydraulic fracturing. Their inflow performance relation (IPR) is tracked to diagnose condensate damage, hydraulic fracture cleanup and differential reservoir pressure depletion. The best IPR data is collected through multi-rate production logging but surface production data serves as an alternative. This paper describes the process of deriving IPR's from production logging and surface production data, and then evaluates 20 years of historic IPR data to quantify the impact of condensate damage and condensate cleanup with progressive reservoir pressure depletion, to demonstrate the massive damage and slow cleanup of hydraulic fractures placed in depleted reservoirs, to show how hydraulic fractures facilitate the vertical cross-flow between isolated reservoir intervals, and to highlight that stress-dependent permeability does not play a major role in this field.

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