Matrix Acidizing with Gelled Acid

2012 ◽  
Author(s):  
Issham Ismail ◽  
Wei Loon Kweh
Keyword(s):  
Xanthan Gum ◽  
Research Study ◽  
High Viscosity ◽  
Injection Rate ◽  
Formation Damage ◽  
Polymer Gel ◽  
Matrix Acidizing ◽  
Steel Core ◽  
Core Holder ◽  
Viscosity Polymer

Suatu uji kaji makmal telah dilakukan untuk membandingkan kecekapan asid gel dan asid lumpur konvensional dalam merawat kerosakan formasi yang disebabkan oleh lumpur dasar air. Suatu sistem pengasidan telah dibina untuk mengkaji kesan kadar alir dan kelikatan asid gel terhadap batu pasir Berea. Peralatan utama yang membentuk sistem pengasidan ialah pemegang teras, sel lumpur, injap, dan tiub 3 mm. Semua komponen ini diperbuat daripada keluli kalis karat. Bendalir perawat yang digunakan dalam uji kaji terdiri daripada asid lumpur (3% HF–12% HCl), asid hidroklorik, dan gel polimer (gam xanthan). Keputusan uji kaji menunjukkan bahawa polimer dengan kelikatan kurang daripada 73 cP memberikan kecekapan yang lebih baik berbanding kelikatan yang melebihi 73 cP. Ini terbukti apabila nisbah kebolehtelapan mencapai 3.5 pada kelikatan gel 73 cP berbanding 1.5 sahaja pada kelikatan 126 cP. Perbezaan nisbah kebolehtelapan yang ketara berlaku kerana polimer yang terlalu likat cenderung untuk memalam liang secara kekal. Asid gel berjaya merawat kerosakan formasi dengan lebih berkesan berbanding asid lumpur, terutama apabila gel polimer berkelikatan 73 cP dialirkan pada kadar alir 0.28 ml/saat, berbanding kadar alir yang lebih rendah. Kata kunci: Teknik lencongan; asid gel; pengasidan; gel polimer A laboratory investigation was conducted to compare the efficiency of gelled acid with conventional/plain mud acid in removing the formation damage induced by water-based mud. An acidizing system was developed to study the effect of flow/injection rate and gel viscosity on Berea sandstone. The main equipments used in this research study were stainless steel core holder, mud cells, valves, and 3 mm tubing. The treatment fluids used were mud acid (3% HF–12% HCl), hydrochloric acid, and polymer gel (xanthan gum). The experimental results revealed that polymer gel with viscosity lower than 73 cP gave better performance as compared to polymer gel with viscosity greater than 73 cP. At gel viscosity of 73 cP, the permeability ratio was 3.5 compared to 1.5 only at viscosity of 126 cP. This was due to the permanent plugging by the high viscosity polymer gel in the core after the injection. Gelled acid has shown tremendous improvement in removing formation damage, where polymer gel with viscosity of 73 cP was found to give better treatment at flow rate of 0.28 ml/s as compared to lower flow rates. Key words: Diversion technique; galled acid; acidizing; polymer gel

A Matrix Acidizing System for Controlled Carbonate Well Stimulation using a Carboxylic Acid Salt with a Chelating Agent

2021 ◽  
Author(s):  
Albert Bokkers ◽  
Piter Brandenburg ◽  
Coert Van Lare ◽  
Cees Kooijman ◽  
Arjan Schutte
Keyword(s):  
Chelating Agent ◽  
Life Time ◽  
Nitrogen Atmosphere ◽  
Injection Rate ◽  
Sodium Gluconate ◽  
Matrix Acidizing ◽  
Well Stimulation ◽  
Stirred Reactor ◽  
Core Flood ◽  
Optimum Injection Rate

Abstract This work presents a matrix acidizing formulation which comprises a salt of monochloroacetic acid giving a delayed acidification and a chelating agent to prevent precipitation of a calcium salt. Results of dissolution capacity, core flood test and corrosion inhibition are presented and are compared to performance of 15 wt% emulsified HCl. Dissolution capacity tests were performed in a stirred reactor at atmospheric pressure using equimolar amounts of the crushed limestone and dolomites. Four different chelating agents were added to test the calcium ion sequestering power. Corrosion tests were executed using an autoclave reactor under nitrogen atmosphere at 10 barg. Core flood tests were performed to simulate carbonate matrix stimulation using limestone cores. It was found that the half-life time of the hydrolysis reaction is 77 min at a temperature of 100 °C. Sodium gluconate and the sodium salt of D-glucoheptonic acid were identified to successfully prevent the precipitation of the reaction product calcium glycolate at a temperature of 40 °C. Computed Tomography (CT) scans of the treated cores at optimum injection rate showed a single wormhole formed. At 150 °C an optimum injection rate of 1 ml/min was found which corresponds to a minimum PVBT of 6. In addition, no face dissolution was observed after coreflooding. Furthermore, the corrosion rates of different metallurgies (L80 and J55) were measured which are significantly less than data reported in literature for 15wt% emulsified HCl. The novelty of this formulation is that it slowly releases an organic acid in the well allowing deeper penetration in the formation and sodium gluconate prevents precipitation of the reaction product. The corrosivity of this formulation is relatively low saving maintenance costs to installations and pipe work. The active ingredient in the formulation is a solid, allowing onsite preparation of the acidizing fluid.

Gastric emptying of nondigestible solids in dogs: a hydrodynamic correlation

1990 ◽  
Vol 258 (1) ◽  
pp. G65-G72 ◽  
Author(s):  
P. J. Sirois ◽  
G. L. Amidon ◽  
J. H. Meyer ◽  
J. Doty ◽  
J. B. Dressman
Keyword(s):  
Particle Size ◽  
Gastric Emptying ◽  
Gravitational Constant ◽  
Particle Density ◽  
Particle Diameter ◽  
High Viscosity ◽  
Fluid Viscosity ◽  
Fluid Flow Rate ◽  
Hydrodynamic Correlation ◽  
Viscosity Polymer

The influence of particle size, particle density, fluid viscosity, and fluid flow rate on the gastric emptying of nondigestible solids was investigated in five dogs with chronically placed fistulas. Six hundred and fifty particles of 13 different size and density combinations were administered simultaneously with 500 ml of either normal saline or low-, medium-, or high-viscosity polymer solutions. The canine stomach was found to discriminate between these solids on the basis of size and density at all levels of viscosity above saline. The observed patterns of emptying are consistent with the hypothesis that gastric emptying of nondigestible solids is governed in part by hydrodynamics and correlate well with the gastric-emptying coefficient (GEC), a dimensionless grouping of variables that takes the form GEC = (Dpy/Dp) [g(rho f - rho p)Dp2]/[eta (nu)] where [g(rho f - rho p)] is particle buoyancy consisting of fluid (rho f) and particle (rho p) densities and g, the gravitational constant; (Dp) is the particle diameter, (Dpy) the estimated pyloric diameter, eta the fluid viscosity, and (nu) the average linear velocity of fluid exiting the stomach.

Design of in-Depth Conformance Gel Treatment to De-Risk ASP Flooding in a Major Carbonate Reservoir

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Abrahim A. Hassan ◽  
Deema Alrukaibi ◽  
Amna Al-Qenae ◽  
Jimmy Nesbit ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
Significant Risk ◽  
High Viscosity ◽  
Carbonate Reservoir ◽  
High Permeability ◽  
Laboratory Design ◽  
Gel Treatment ◽  
Viscosity Polymer ◽  
Chromium Acetate

Abstract Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor sweep efficiency, both areal and microscopic. An Alkaline-Surfactant-Polymer (ASP) pilot is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Design of the gel conformance treatment was multi-faceted. Rapid breakthrough of tracers at the pilot producer from each of the individual injectors, less than 3 days, implied a direct connection from the injectors to the producer and poses significant risk to the success of the pilot. A dynamic model of the SAMA pilot was used to estimate in the potential injection of either a high viscous polymer solution (~200 cp) or a gel conformance treatment to improve contact efficiency, diverting injected fluid into oil saturated reservoir matrix. High viscosity polymer injection scenarios were simulated in the extracted subsector model and showed little to no effect on diverting fluids from the high permeability streak into the matrix. Gel conformance treatment, however, provides benefit to the SAMA pilot with important limitations. Gel treatment diverts injected fluid from the high permeability zone into lower permeability, higher oil saturated reservoir. After a gel treatment, the ASP increases the oil cut from 3% to 75% while increasing the cumulative oil recovery by more than 50 MSTB oil over ASP following a high viscosity polymer slug alone. Laboratory design of the gel conformance system for the SAMA ASP pilot involved blending of two polymer types (AN 125SH, an ATBS type polymer, and P320 VLM and P330, synthetic copolymers) and two crosslinkers (chromium acetate and X1050, an organic crosslinker). Bulk testing with the polymer-crosslinker combinations indicated that SAMA reservoir brine resulted in not gel system that would work in the SAMA reservoir, resulting in the recommendation of using 2% KCl in treated water for gel formulation. AN 125 SH with S1050 produce good gels but with short gelation times and AS 125 SH with chromium acetate developed low gels consistency in both waters. P330 and P320 VLM gave good gels with slow gelation times with X1050 crosslinker in 2% KCl. Corefloods with the P330-X 1050 showed good injectivity and ultimately a reduction of permeability of about 200-fold. A P330-X 1050 was recommended for numerical simulation studies. Numerical simulator was calibrated by matching bulk gel viscosity increases and coreflood permeability changes. Numerical simulation indicated two of the four injection wells (SA-0557 and SA-0559) injection profile will change compared to water. Overall injection rate was reduced by the conformance treatment and was the corresponding oil rate. Total oil production from the center pilot production well (SA-0560) decreased with gel treatment but ultimately increased to greater rates

Field Implementation of In-Depth Conformance Gel Treatment Prior to Starting an ASP Flooding Pilot

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Abrahim Hassan ◽  
Naser Alajmi ◽  
Jimmy Nesbit ◽  
Bastien Thery ◽  
...  
Keyword(s):  
Polymer Solution ◽  
Injection Pressure ◽  
High Viscosity ◽  
Production Well ◽  
Sweep Efficiency ◽  
Injection Wells ◽  
Appreciable Change ◽  
Well Pattern ◽  
Gel Treatment ◽  
Viscosity Polymer

Abstract Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor volumetric sweep efficiency, both areal, vertically, and microscopically. An Alkaline-Surfactant-Polymer (ASP) pilot using a regular five-spot well pattern is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Each of the four injection wells in the SAMA ASP pilot was treated with a chemical conformance improvement formulation. A high viscosity polymer solution (HVPS) of 200 cP was injected prior to a gelant formulation consisting of P300 polymer and X1050 crosslinker. After a shut-in period, wells were then returned to water injection. Injection of high viscosity polymer solution (HVPS) at the four injection wells showed no increase in injection pressure and occurred higher than expected injection rates. Early breakthrough of polymer was observed at SA-0561 production well from three of the four injection wells. No appreciable change in oil cut was observed. HVPS did not improve volumetric sweep efficiency based on the injection and production data. Gel treatment to improve the volumetric conformance of the four injection wells resulted in all the injection wells showing increased of injection pressure from approximately 3000 psi to 3600 psi while injecting at a constant rate of approximately 2,000 bb/day/well. Injection profiles from each of the injection well ILTs showed increased injection into lower-capacity zones and decreased injection into high-capacity zones. Inter-well tracer testing showed delayed tracer breakthrough at the center SA-0561 production well from each of the four injection wells after gel placement. SA-0561 produced average daily produced temperature increased from approximately 40°C to over 50°C. SA-0561 oil cuts increased up to almost 12% from negligible oil sheen prior to gel treatments. Gel treatment improved volumetric sweep efficiency in the SAMA SAP pilot area.

Three-Dimensional Finite Element Analysis of Polymer Coextrusion through Cylindrical Channel

2011 ◽  
Vol 291-294 ◽  
pp. 542-546
Author(s):  
Min Zhang ◽  
Chuan Zhen Huang ◽  
Sheng Sun ◽  
Yu Xi Jia ◽  
Tian Jiang Liang
Keyword(s):  
Finite Element ◽  
Three Dimensional ◽  
Outer Region ◽  
Polymer Melt ◽  
High Viscosity ◽  
Element Analysis ◽  
Low Viscosity ◽  
Dimensional Finite Element ◽  
Three Dimensional Finite Element ◽  
Viscosity Polymer

The eccentricity coextrusion flow of polymer melt was analyzed based on finite element simulations. Such simulated results as the fields of flow velocity, pressure and shear stress were obtained. Through the analysis of the results, the mechanism of the column interface forming in the axis-symmetry coextrusion flow path was obtained. For the coextrusion flow, if the low viscosity polymer flows near the die wall, the flow would be steady. Whereas, if the polymer with low viscosity is in the core and the high viscosity polymer at the outer region, Which is disadvantage in terms of energy, and the instability flow would occur. This is also accord with the least energy consume theory.

The Reorganization Coalescence Oil-Removing Device and the Effect of Treating Polymer Flooding Produced Liquid

2013 ◽  
Vol 726-731 ◽  
pp. 1994-1998
Author(s):  
Lei Zhang ◽  
Zhong Min Wang ◽  
Hai Tao Ma ◽  
Wei Gang Wang ◽  
Jun Jie Yang
Keyword(s):  
Removal Rate ◽  
Polymer Concentration ◽  
High Viscosity ◽  
Suspended Solid ◽  
Polymer Flooding ◽  
The Novel ◽  
Viscosity Polymer

In view of problem of the coalescence material jam and the demulsification lower by using the Coalescence oil-removing device which was using to treat high viscosity polymer flooding. The novel Coalescence oil-removing device was developed through the optimization of coalescence material and reasonable backwashing system designing, which can realize coalescence material regeneration and improve oil strains of coalescence effect. At the condition that polymer concentration was 426mg/L, pH=8.75, average oil was 365mg/L, suspended solid (SS) was 75mg/L; The oil of effluent can reach 50mg/L below, removal rate reached 86%; SS of the out water can reach 30mg / L, the removal rate reached 60%.

scholarly journals Optimization of Cyclic Steam Stimulation Process Using Response Surface Methodology

2021 ◽  
Vol 2 (1) ◽  
pp. 26
Author(s):  
Suranto A.M. ◽  
Eko Widi Pramudiohadi ◽  
Anisa Novia Risky
Keyword(s):  
Response Surface Methodology ◽  
Response Surface ◽  
Heavy Oil ◽  
Steam Injection ◽  
High Viscosity ◽  
Injection Rate ◽  
Operating Conditions ◽  
Steam Quality ◽  
Cyclic Steam Stimulation ◽  
Steam Stimulation

Heavy oil has characteristics such as API gravity 10-20 and high viscosity (100-10,000 cp) at reservoir temperature. Several methods have been successfully applied to produce these reserves, such as cyclic steam stimulation (CSS). Cyclic steam stimulation is a thermal injection method that aims to heat the oil around production wells. This paper presents the investigation regarding CSS application in heavy oil using Response Surface Methodology. Several scenarios were done by varying the operating conditions to obtain the most realistic results and also evaluating the factors that most influence the success of CSS process. Optimization is performed to find the maximum recovery factor (RF) value and minimum steam oil cumulative ratio (CSOR). The operating parameters used are CSS cycle, steam injection rate, and steam quality. Then statistical modeling is carried out to test the most important parameters affecting RF and CSOR for 10 years. The simulation results show that the CSS cycle, steam injection rate, and steam quality affect the RF and CSOR. The maximum RF results with the minimum CSOR were obtained at 39 cycles, an injection rate of 300 bbl/day, and a steam quality of 0.9 with an RF and CSOR value is 24.102% and 3.5129 respectively.

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