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First EAGE Workshop on Well Injectivity and Productivity in Carbonates
- Conference date: March 30-April 1, 2015
- Location: Doha, Qatar
- Published: 30 March 2015
1 - 20 of 25 results
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Injection Water Compatibility and Scale Deposition Study for a Low-Permeability Carbonate Reservoir Development Project
Authors P.I. Osode, M.A. Bataweel, P.P. Najeeb and M.H. KhaldiSummaryInjection water compatibility investigation with formation rock and fluid at in-situ conditions is imperative in determining the optimum economic treatment facility requirements. Laboratory experiments were carried out in addition to software simulation to appraise the risk of inorganic scale deposition in a hitherto undeveloped carbonate reservoir within a producing field.
Coreflood and fluid-fluid compatibility tests were carried out at an estimated bottom-hole temperature of 150 °F and pressure of 1,000 psi. Comprehensive mixed-brine simulation software was also used to determine the inorganic scaling tendency expected with the use of seawater, produced water and diluted produced water for the planned injectors.
The laboratory test and simulation results showed that there was indeed a high risk of scale precipitation due to the high Calcium ion content of the formation brine while the diluted produced water gave the least risk. The results also indicated that highest risk of inorganic scale precipitation was at approximately 1:1 mix ratio for the formation brine/seawater mixture and 3:2 mix ratio for formation brine/produced water mixture.
This paper discusses the experiments and simulation conducted for scale prediction analysis of injection water in addition to providing an insight into scale risks associated with water injection in high divalent-salt environment
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Sensitivity Analysis of Modeling Reservoir Formation Damage by an Adjoin-state Two-phase Particulate Transport Simulator
Authors M.A. Sbai and M. AzaroualSummaryQuantifying productivity/injectivity performance in highly heterogeneous carbonate reservoirs remains a challenge because of the interaction of many interdependent processes belonging to different scales. In particular, dynamics of particulate suspensions at the Darcy scale are intimately related to the competing mechanisms of hydrodynamic/colloidal release from pore surfaces, and blocking in pore bodies/throats. Additionally, within immiscible two-phase flows additional processes occur such as interphase mass transfer.
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Towards Unified Thermodynamic Modeling of Fluids in Carbonate Reservoir Environments
Authors D.K. Eriksen, S. Dufal, S.Z.S. Al Ghafri, E. Forte, A. Galindo, G. Jackson, J.P.M. Trusler, E.A. Müller and A.J. HaslamSummaryWe provide a brief overview of the SAFT-VR Mie theory and its application to reservoir-relevant fluids, including aqueous mixtures incorporating CO2 and hydrocarbons; we feature its use in conjunction with experimental thermophysical-property measurements. The modeling of electrolyte solutions, such as brines, illustrates its straightforward extension to include more-complex interactions. We introduce our molecular-based approach to modeling interfacial tension, highlighting its close connection with SAFT-VR Mie. We discuss our method for characterising the interaction between a fluid and a solid substrate, demonstrating how this will be incorporated in an integrated approach with SAFT-VR Mie to calculate, for example, adsorption on the rock surface. Together, these will provide an integrated framework for the calculation of fluid thermodynamics in injection and production processes.
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Development of Novel Emulsified Acid using Waste Oil
Authors A.S. Sultan and Z. SidaouiSummaryResults showed the potential use of waste oil to prepare high temperature emulsified acid (up to 300°F). The rheological data confirms the stability of the new emulsified formulation at higher temperature. This paper summarizes the findings of using waste oil emulsion and recommends it for field applications. The newly proposed emulsified acid introduces waste oil as replacement of diesel.
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Impact of Mineral Heterogeneity on Wormhole Propagation in Matrix Acidizing and the Shortcomings of the Damkholer Number-based Designs
Authors M.A. Sbai, M. Azaroual and L. AndréSummarySustainable and successful exploitation of the underground resources (oil, gas, geothermal energy, water, etc.) is intimately dependent on the performances of the well and the near-wellbore to optimally deliver these resources. In carbonate reservoirs, acid stimulation by matrix acidizing has been a method of choice to restore and/or improve well productivity and/or injectivity index. An optimal reaction rate leads to a dissolution regime for which wormholes connect the wellbore and the initial reservoir permeability. The success of this operation depends mainly on the permeability distribution, injection rate, mineral reaction rates and the chemical speciation of reservoir/acid.
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Optimisation of Onsite Acid Pumping Rates Based On Laboratory Flow Rates
Authors S. Goedeke, O. Gharbi, M. Al-Sammarraie, N. El-Cheikh and C. FrancoSummaryWell stimulation treatments using acid have been performed for over 100 years. Over time the industry has become well aware that acidizing can not only connect to the natural fracture system but also increase water production.
In order to achieve the best stimulation result with the lowest skin possible using the least amount of acid without fracturing the formation an optimized pumping rate is required. Pumping at optimized rates will lead to an increased efficiency of matrix acid stimulation jobs.
An approach is outlined to optimize on site pumping rates as well as acid coverages (gal/ft) using laboratory flowrates. Constant pumping rates as well as pumping at an increasing rate schedule have been investigated. As a first step the maximum pumping rate based on the breakdown pressure of the formation should be determined. Graphs of pumping rate vs. total skin for different acid coverages can then be calculated to determine the optimum pumping rate for a certain stimulation scenario.
The results of this modeling study show that at a certain point an increased pumping rate does not further decrease the skin value, however pumping below the optimum rate can significantly impact stimulation results negatively.
For horizontal permeability ratios between khmax and khmin of up to 55, porosity fractions between 0.05 and 0.3 and formation thicknesses up to 300 ft, pumping rates between 2 bpm to 8 bpm can be sufficient to create optimum wormholing. For very high permeability contrasts such as the investigated permeability ratios between khmax and khmin of 500 most of the acid is lost into high permeability zones and the well does not get effectively stimulated. Operationally, an increasing rate schedule is recommended over a constant rate schedule because an increasing rate schedule can deliver a deeper wormhole penetration.
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Acid Wormholing in Carbonate Reservoirs: Successes and Future Challenges
Authors D.R. Guerillot and V.R. AmbatiSummaryCarbonate rock formation in petroleum reservoirs are highly heterogeneous in nature exhibiting complex porosity and permeability variations leading to irregular pore scale flow paths. Therefore, developing wormholes by acid stimulation in reservoir wells is favored for better injectivity and productivity of the wells. Determining and attaining a regime for wormhole generation in carbonates is very challenging as it depends on the variability of these petrophysical parameters. The objective of the present study is to stimulate the discussions on the following key questions:
- How well-understood are the key mechanisms of the reactive-transport phenomena in acid wormholing?
- What are the state-of-the-art numerical modelling techniques to capture this phenomena and associated commercial software’s in the market?
- How well-understood is this phenomena in the laboratory? And how valid are are the numerical predictions for laboratory experiments?
- How deterministic is to characterize and predict acid wormholing in carbonate reservoirs?
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Non-Damaging Thin Polymer Drilling Fluid Improves O&G Wells’ Productivity at Lower Drilling Operational Cost
By A.M. AhmedSummaryDrilling fluid is a relatively minor direct expense (< 7% of the total drilling costs), but it can significantly affect principal item in drilling expense (which is time ∼ 37%) and other items of expense, such as drill pipe, casing, bits, formation logging/testing, cementing, etc. (probably ∼ 26%).
Any formation damage due to using improper drilling fluid could affect the produtivity of the pay zone and increase post treatment costs. In case of permanent formation damage, lost cannot be described by certain amount of money. Therefore, performance of the drilling fluid is more important than it’s cost, i. e., an optimal drilling fluid system must be targeted.
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Utilization of Iron Oxide Nanoparticles in Drilling Fluids Improves Fluid Loss and Formation Damage Characteristics
Authors Z. Vryzas, P. Arkoudeas, O. Mahmoud, H. Nasr-El-Din and V. KelessidisSummaryA key aspect during drilling operations is formation damage of productive formations by drilling fluids, which is examined to ensure an effective well completion. Drilling fluid is the blood of the well and the success of a drilling operation is closely related with its efficiency. The fluids provide pressure control in the wellbore, transfer the drilled cuttings to surface and seal possible fractures, thus preventing fluid loss and formation damage. Filtrate invasion can cause wellbore problems reducing productivity significantly. Thus drilling fluid formation damage characteristics need to be examined and controlled appropriately by using the right additives. Maintaining the optimal concentrations of these additives is vital for well integrity. Rheological and fluid loss characteristics are key fluid properties that need to be optimized for the development of stable and “smart” water-based fluids.
The objective of this research is to develop appropriate additives in order to reduce formation damage in drilling operations. We do this by examining the fluid loss characteristics for water-based muds, utilizing iron oxide nanoparticles as fluid loss additives. The nanoparticles benefit from their small size and it is anticipated to seal porous and/or fractured formations and thus are expected to provide a great potential for reduction of formation damage.
We present API filtrate loss and filter cake characterization along with the changes in the rheological properties of drilling fluids containing various concentrations of nanoparticles. We have measured rheological properties with Couette type viscometer both at low and high temperatures. LPLT and HPHT API filter presses have been used for fluid loss measurements. Scanning Electron Microscope (SEM) pictures were used to analyze the nanoparticle size range and to reveal secrets of their good performance by providing deep insights for their microstructure, the interfacial phenomena and the interaction between bentonite particles and the nanoparticles.
The examined nanoparticles have the potential not only to significantly reduce the fluid loss and develop a thin mudcake, but also to maintain optimal rheological properties thus providing effective pressure control. The required relatively low concentration in the drilling fluid provides a base for more efficient, environmental friendly and safer drilling practices.
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Asphaltene Precipitation and Deposition from a Heavy Crude Oil with CO2
Authors C.M. Seifried, J.P. Crawshaw and E.S. BoekSummaryAsphaltene precipitation and subsequent deposition may lead to severe problems during crude oil production, transportation and processing. During production they can deposit in reservoir rock pores, which may lead to a reduction in permeability and possible formation damage. Asphaltene precipitation can be triggered due to a change in temperature, pressure and/or oil composition. The oil composition can be altered by mixing crude oil and carbon dioxide (CO2). CO2 for Enhanced Oil Recovery (EOR) purposes has been injected into reservoirs since the 1970’s, which has seen an increase in the recovery of residual oil. However, the possible deposition of asphaltenes is one of the costliest problems the oil industry has to deal with. Despite significant research, asphaltene deposition under flowing conditions remains barely understood ( Gonzalez et al. 2008 , Seifried et al. 2013 ). Further research is required to identify the conditions that will cause the onset of asphaltene precipitation with CO2 and the subsequent amount of asphaltene precipitated.
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The Effect of Various Additives on Matrix Acidizing Effectiveness in Carbonate Reservoirs
Authors G. Penny, D. Biswas, D. Germack, D. Shedd and N. El DinSummaryMatrix acidizing of carbonate reservoirs presents a challenge in the middle east as the horizontal legs become longer some now as long as 30,000 ft with some reservoirs at temperatures above 300 F. In this work we have investigated the diffusivity of acids and alternative acids with various additives vs temperature using a rotating disc apparatus. The pore volume to breakthrough (PVBT) was then measures on various carbonate cores such as Indiana Lime and cores form various Middle East formations. To show the impact of acid and additive selection we have built a horizontal wellbore simulator to predict the impact of lithology, acid type and various additives upon diffusivity and productivity.
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A 1H NMR Study on Acidized and Non-acidized Carbonate Rock Cores to Explore Correlations Between Pore Geometry and Fluid-Solid Interactions
Authors V. Kelessidis, L. Lagkaditi, M. Fardis, M. Karayanni, A. Anastasiou, K. Dong, D. Hill and G. PapavassiliouSummaryCarbonate reservoirs are heterogeneous systems at multiple length-scales, a characteristic that influences strongly their petrophysical properties and oil recovery procedures [1]. Wettability for example, capillary pressure as a function of water saturation, and partial permeability, are related with the pore structure (pore size and shape) and the rock mineralogy [2, 3]. Acid stimulation treatments are available, which can improve productivity [4, 5, 6]. It is expected that acid stimulation treatment, which opens rock porous channels known as wormholes, will influence strongly the pore structure and therefore petrophysical properties around the wormholes, decreasing wettability and thus increasing oil recovery.
In this work we study the role of the pore structure on the water and oil absorption in a number of acidized and non-acidized carbonate cores by employing 1H NMR.
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An Effective Approach to Improve Acid Stimulation of Low-Permeability Carbonate Formation in Long Horizontal Water Injection Wells: Case Histories
By A. Al-TaqSummaryHydrochloric acid effectively dissolve calcium carbonate mineral present in the filter cake and the formation, but is not capable of dissolving or degrading some of mud damaging components (polymers). Lab results indicate that the conventional acidizing practice was not effective and yielded a loss in the initial core permeability of more than 80%. Based on lab findings, an initial stage of flowing back the well prior to acid stimulation was recommended. This stage was intended to remove as much as possible of mud debris and prevent some polymers from penetrating into the formation, a main cause of injectivity decline. It will also improve the contact of injected acids with the treated formation.
Application of this technique in three carbonate power water injectors resulted in significant improvement in their injectivity index. The paper presents six field cases in the same carbonate formation: three wells were treated with the typical acid stimulation practice and the others were treated using the new method. The post treatment injectivity tests revealed that the wells treated using the new method had more than 2fold increase in injection rates at lower injection pressures compared with those treated using the typical acid stimulation practice.
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Experimental Investigation of Improved Acid Stimulation in Carbonates
Authors O.G. Gharbi, M.A.S. Al-Sammarraie, J.C.B. Benquet, S.G. Goedeke, N.E.C.A. ALI and E.A. AubrySummaryIn this study, we aim to experimentally revisit standard acid stimulation techniques and to test novel pumping sequences including water mitigation and diversion. After state of the art characterization of the selected carbonate samples, injections of acidic solutions are performed at elevated temperatures and pressures using dedicated single and dual core apparatus at the core scale. It has been found that, wormholing behavior and mainly the pore volume to breakthrough is strongly dependent on the acid type and the pumping mode. For retarded acids, such as emulsified acids, the existence of the optimum pore volume to breakthrough is challenged.The efficency of different pumping sequences on water mitigation and diversion is discussed.
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Effect of High Pressure on the Propagation of Wormhole in Carbonate Rocks: Experimental and Modeling Approach
Authors A.S. Sultan, L. Kareem and Q. QiuSummaryThe primary focus of this presentation is to establish good understanding of the rock dissolution under high pressure and moderate temperature conditions for tight reservoirs. There are various parameters involved in such studies which include but not limited to the flow rate of acid, the concentration of the acid, rock type, rock properties, temperature and pressure. There have been vast studies reported in the literature; however, experiments with such high pressures have not been conducted before.
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Evaluation of Petrophysical Parameters from Micrometer Resolved CT Data
Authors T.I. Solling, V. Ambati, J. Foeken and D. GuérillotSummaryThe portfolio of methods for pore level characterization of reservoir rocks has significantly advanced over the last decade with the advent of micron and submicron resolution computed tomography methods. This in combination with image processing software for integration of CT data with results from scanning electron microscopy measurements and automated mineralogy has in principle enabled full 3D mapping of pores spaces and the associated mineralogy. With such data in hand it is possible to calculate for example absolute permeabilities. We show examples of the limitations and advantages of this approach for two rock types: one which is easily characterized and one which is more difficult. We will focus on the importance of the resolution and the caveats in the subsequent computational treatment.
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Organoclay as Emulsifier for Water in Oil Polymeric Gel Formulations used in Conformance Control
Authors A.S. Sultan, A. Mohamed and I. HusseinSummaryThe new emulsifier can form high quality water in oil (W/O) emulsions and improve the thermal stability of emulsified polymers or acid solution. The stability of the emulsion can be controlled by controlling emulsifier concentration; the emulsion system can withstand high salinity much better than current surfactants used in oilfields. These emulsifiers will be appropriate for wellbores having high pressure and high temperature (120°C) with high salinity field water (221,673 ppm).
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Methodologies Used to Estimate Swept Fracture Volume and to Design Gel Polymer Treatments for Profile Modification, Sweep Improvement, and Water Shut--off in Prolific Natural Waterdrive
Authors A.D. Biswas, J. Portwood and G. PennySummaryThis paper will describe new and unique methods that are being developed and used to more accurately size and design gel polymer treatments at injectors and producer wells. These techniques include novel diagnostic plots and mathematical predictive models used to forecast results and economics, and the predictive accuracy of the model is confirmed against field case studies. The paper will also present a statistical evaluation of nearly 100 treatments, comparing water reduction and incremental oil recovery to variables like gel polymer volume, oil gravity, formation thickness and lithology, depth, and injection pressure, to name a few.
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Inter-well Tracer and Marker Monitoring Strategies in Carbonates
Authors H. Preud’homme, N. Kuiper, C. Rowell and B. ShomarSummaryIn a multi-well tracing test, one of the key parameters is the selection of an appropriate tracer molecule and its relative analytical process regarding the local environmental and operational constraints. Many tests in the past have been unsuccessful due to improper tracer selection. The first part of this presentation provides guideline data and advice on selecting the best possible tracers/markers and analytical processes for a tracing campaign according to the test’s main objective which may be linked to the inter-well network, connectivity/injectivity, flow allocation, residual oil saturation, etc.
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Best Practices for a Sustainable PWRI
By J. OchiSummaryProduced water re-injection or PWRI is an important strategy for deriving value from waste waters because it offers the benefit of an environmentally attractive disposal technique and it can also participate to reservoir sweep improvement and pressure maintenance.
Before any implementation of PWRI project, specifications of produced water quality in terms of solid and oil contents must be determined to allow designing water treatment installations. Also, specifications of injection pressure must be determined to allow designing injection pumps and network. If not designed correctly, PWRI can face injectivity decline which end in loss of production or safety issues in term of cap rock integrity.
A correct PWRI project design is not a simple matter and needs heavy lab experiments, sophisticated tools and the Company’s know-how acquired through field experience feedback. The purpose here is to share Total’s experience in this domain by presenting the key factors to be considered and the traps to be avoided to make any PWRI project successful.
The presentation should answer questions like: which injection flow regime for PWRI and why, how to determine specifications for water, is there any simple rules, what represent core flood tests with regard to the well, how to link both, how to forecast injection pressure and how to determine maximum allowable pressures, what software to use, how to assess uncertainties, what to do if injectivity deteriorates eventually, is there any remedial technique?
The answers to these questions will be illustrated by field examples with carbonates and sandstones.
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