Applying New Systematic and Dynamic UBD Procedures to Prevent Formation Damage, Wellbore collapse and Improve Oil production in Hassi Massoud field

2008 ◽  
Author(s):  
Ali Berkat ◽  
Khelil Kartobi ◽  
Amine Mazouzi ◽  
Okba Dhina ◽  
Hani H. Qutob ◽  
...  
Keyword(s):  
Oil Production ◽  
Formation Damage

Monte Carlo Risk Assessment of Formation Damage Caused by Asphaltene Deposition

2021 ◽  
pp. 1-8
Author(s):  
Arley S. Carvalhal ◽  
Gloria M. N. Costa ◽  
Silvio A. B. Vieira de Melo
Keyword(s):  
Monte Carlo ◽  
Probability Distribution ◽  
Oil Production ◽  
Rock Properties ◽  
Formation Damage ◽  
Permeability Reduction ◽  
Prevention Policy ◽  
Oil Composition ◽  
Hypothetical Scenario ◽  
Asphaltene Deposition

Summary Uncertainties regarding the factors that influence asphaltene deposition in porous media (e.g., those resulting from oil composition, rock properties, and rock/fluid interaction) strongly affect the prediction of important variables, such as oil production. Besides, some aspects of these predictions are stochastic processes, such as the aggregation phenomenon of asphaltene precipitates. For this reason, a well-defined output from an asphaltene-deposition model might not be feasible. Instead of this, obtaining the probability distribution of important outputs (e.g., permeability reduction and oil production) should be the objective of rigorous modeling of this phenomenon. This probability distribution would support the design of a risk-based policy for the prevention and mitigation of asphaltene deposition. In this paper we aim to present a new approach to assessing the risk of formation damage caused by asphaltene deposition using Monte Carlo simulations. Using this approach, the probability-distribution function of the permeability reduction was obtained. To connect this information to a parameter more related to economic concepts, the probability distribution of the damage ratio (DR) was also calculated, which is the fraction of production loss caused by formation damage. A hypothetical scenario involving a decision in the asphaltene-prevention policy is presented as an application of the method. A novel approach to model the prevention of asphaltene aggregation using inhibitors has been proposed and successfully applied in this scenario.

Resolving Multiple Formation Damage Mechanism in Carbonate Reservoir Through Systematic Approach Using Combination of Aromatic Solvent and Less Aggressive Acid

2021 ◽  
Author(s):  
Hamzah Kamal ◽  
Prakoso Noke Fajar ◽  
Ghozali Farid ◽  
Aryanto Agus ◽  
Priyantoro Tri Atmojo ◽  
...  
Keyword(s):  
Systematic Approach ◽  
Oil Production ◽  
Damage Mechanism ◽  
Carbonate Reservoir ◽  
Formation Damage ◽  
Water Production ◽  
Aromatic Solvent ◽  
Well Productivity ◽  
Production Phase ◽  
Water Breakthrough

Abstract There is no well operation that is truly non-damaging. Any invasive operation, even production phase itself, may be damaging to well productivity. An interesting case was found in L-Field which is located in South Sumatra, Indonesia. All four wells are predicted to cease to flow after five-year production and artificial lift have to be installed to prevent steep decline in oil production. Unfortunately, all of wells’ productivity index (PI) decreased post well intervention and therefore, couldn’t achieve target. The PI was continuously decreasing during production phase and aggravated the decline in oil production. Remediation action by systematic approach was applied to solve the problem. Early diagnostic revealed some potential causes through evaluation of both production and well treatment data. Laboratory test such as mineralogy analysis, crude composition and water analysis, solubility and compatibility test have been conducted and clarified the root cause that formation damage occurred in multiple mechanism related to incompatibility of the workover fluid and organic deposition. Then, possible well treatments were listed with pros and cons by considering post water production related to the carbonate reservoir properties. Subsequently, chemical matrix injection was ranked based on less possibility of water breakthrough risk. Diesel fuel and de-emulsifier injection was decided as the first treatment in order to remove formation damage caused by organic deposition. The rate was increased temporary with Water Cut (WC) remained at the same level. The subseqeuent effort was to inject low reaction chelating acid and the result showed temporary improvement and the production did achieve significant gain. Finally, the third attempt indicated promising results with the injection of aromatic solvent followed by chelating acid. The well productivity was increased to more than 20 times of the pre treatment levels. The method can be replicated to other affected wells with similar damage mechanism. High vertical permeability over horizontal permeability becomes a real threat in carbonate strong water driver reservoir in L-field. Thus, matrix acidizing treatment has to be carefully applied to prevent unwanted water production. Non-aggressive and slow reaction acid were chosen to prevent face dissolution reaction that leads to water breakthrough.

A New Systematic and Dynamic UBD Procedures Applied to Prevent Formation Damage, Wellbore Collapse and Improve Oil Production in Hassi Massoud Field

2009 ◽  
Author(s):  
Ali Berkat ◽  
Khelil Kartobi ◽  
Amine Mazouzi ◽  
Okba Dhina ◽  
Hani H. Qutob ◽  
...  
Keyword(s):  
Oil Production ◽  
Formation Damage

Green Well Stimulation Fluids for Enhanced Oil Recovery from Tight Sand Formations: Field Wide 70+ Wells Study Over 4 Years

2021 ◽  
Author(s):  
Martin Shumway ◽  
Ryan McGonagle ◽  
Anthony Nerris ◽  
Janaina I.S. Aguiar ◽  
Amir Mahmoudkhani ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Cost Effective ◽  
Field Trials ◽  
Lessons Learned ◽  
Formation Damage ◽  
Well Stimulation ◽  
Tight Formations ◽  
History Of ◽  
Organic Deposits

Abstract Legacy oil production from Appalachian basin has been in a decline mode since 2013. With more than 80% of wells producing less than 15 bbl/day, there is a growing interest in economically and environmentally viable options for well stimulation treatments. Analysis of formation mineralogy and reservoir fluids along with history of well interventions indicated formation damage in many wells due precipitation of organics and a change in wettability being partially responsible for production decline rates in excess of forecasts. The development and properties of a novel cost-effective biosurfactant based well-stimulation fluid are described here along lessons learned from several field trials in wells completed in the Upper Devonian Bradford Group. This group of 74 wells, completed in siltstone and sandstone reservoirs were presenting more than 12 well failures annually across the field, which was attributed to the accumulation of organic deposits in the tubulars. Based on these cases, batch stimulation treatments using a novel fluid comprising biosurfactants were proposed and implemented field wide. The treatments effectively removed organic deposits, changed formation wettability from oil to water wet and resulted in a sustained oil production increase. Well failures were significantly reduced as a result of this program and the group of 74 wells did not have a paraffin-related well failure for 18 months. Results from this program demonstrates the efficiency of the green well stimulation fluids in mitigating formation damage, reducing organics deposition and in increasing oil production as a promising method to stimulate tight formations.

Applying a New Systematic and Dynamic UBD Procedure Prevented Formation Damage, Wellbore Collapse and Improved Oil Production in Hassi Massoud Field

2009 ◽  
Author(s):  
Hani H. Qutob ◽  
Ali Berkat ◽  
Ayman Sh. Badi Marei ◽  
Okba Dhina ◽  
Amine Mazouzi ◽  
...  
Keyword(s):  
Oil Production ◽  
Formation Damage

scholarly journals Current status and development trends of efficient oil production testing technology

2021 ◽  
Vol 236 ◽  
pp. 01017
Author(s):  
Ning Kun ◽  
Yu Gang ◽  
Mu Lingyu ◽  
Wu Xi
Keyword(s):  
Operating Cost ◽  
Operating Time ◽  
Oil Production ◽  
Thin Layers ◽  
Current Status ◽  
Formation Damage ◽  
Production Testing ◽  
Testing Phase ◽  
Testing Method ◽  
Testing Technology

Oil production testing is a critical tool to understand reservoir properties and well producibility. The development of oil production testing technology in China has mainly gone through three phases: conventional oil production testing phase, oil production testing phase, and integrated oil production testing phase. Currently, domestic and overseas oilfields are still adopting the traditional oil production testing method, which contains plenty of repetitive processes that cost longer operating time, higher operating cost, formation damage caused by excessive high-density fluid, and many other shortcomings. Also, the difficulties of oil production testing in the deep and ultra-deep well under HPHT conditions are significant. Analyzing the development trend of oil production testing, there are two main topics identified: oil production testing for separated layer via one trip string and Pad-free oil production testing method. The oil production testing for separated layer via one trip string was developed for testing formations where lamination and thin layers are presented and causing interference among the testing layers. The Pad-free oil production testing methodology was developed for testing wells that fail to obtain reservoir fluid properties due to the formation damage caused by a high fluid density pad. This paper is aiming to summarize and analyze the most advanced oil production testing technology worldwide and innovations had been made to the oil production testing field, hopefully inspired researchers to develop possible future uses and further improvements in efficiency. Facing the challenges of low gas prices, only continuous innovation in technology and the upgradation of tools and equipment can achieve the goal of improving quality and increasing efficiency.

scholarly journals Field Experiments of Different Fracturing Designs in Tight Conglomerate Oil Reservoirs

2021 ◽  
Author(s):  
Daiyan Zhang ◽  
Shiying Ma ◽  
Jing Zhang ◽  
Yue Zhu ◽  
Bin Wang ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Field Experiments ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Formation Damage ◽  
Fracturing Fluid ◽  
Fracture Spacing ◽  
The Poor ◽  
The World ◽  
The Cost

Abstract Mahu oilfield is currently the largest tight conglomerate reservoir in the world, where Ma-131 and Ma-18 plays are the first two commercially developed reservoirs. In order to reduce the cost and explore the best fracturing parameters, field experiments have been conducted in these two plays since 2017. The types of proppant and fracturing fluid, the slickwater ratio, and the fracture spacing are mainly changed for comparison, and fracturing effects are evaluated to establish a reference for developing the neighboring plays in Mahu oilfield. This paper summarizes the fracturing parameters and production histories of 74 wells in Ma-131 and Ma-18 plays during four years of field operations. Firstly, results indicate that silica sands perform similar to ceramics in the Ma-131 play where the reservoir depth is smaller than 3300 m; however, in the Ma-18 play where the reservoir is deeper than 3500m, increasing the sand volume by 1.1 times still cannot reach the production in wells using ceramics. Secondly, when the fracture spacing is reduced, both oil production and water flowback become even smaller in wells using sands than those using ceramics; this is due to the increase of closure pressure and decrease of fluid volume per cluster respectively. Thirdly, when the crosslinked guar is replaced by the slickwater, no obvious change in oil production is noticed even though the volume of fracturing fluid is almost doubled; limited lengths of propped fractures due to the poor proppant-carrying ability of slickwater likely offset the production enhancement from the decrease of formation damage by slickwater. This paper summarizes learnings from the field experiments during four years of development in Mahu oilfield, and help guide the optimization of hydraulic fracturing parameters for future wells.

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