Scale Removal In A Deepwater Oil Production Well Using Fresh Water

2021 ◽  
Author(s):  
Paulo Henrique de Amorim Martins ◽  
Bruno Marins Freiman
Keyword(s):  
Fresh Water ◽  
Water Solubility ◽  
Produced Water ◽  
High Volume ◽  
Carbonate Reservoir ◽  
Scale Removal ◽  
Production Wells ◽  
Reducing Costs ◽  
Production Tubing ◽  
Scale Deposition

Abstract The aim of this paper is to present the results obtained by the use of fresh water in order to remove inorganic scale deposited inside production tubing from carbonate reservoir deepwater production wells with high salinity and low BS&W. The paper covers the entire process from the identification of production loss, the investigation of its main causes, treatment propositions and discussion of obtained results. One of the hypotheses regarding the scale deposition mechanism in the studied wells is that the precipitation of salts is due to the evaporation of produced water. This phenomenon occurs through the contact of water with dry gas applied in the artificial elevation method (gas lift). The proposed and tested scale removal procedure consists of a soaking of the production tubing with fresh water in order to dissolve the deposition or at least part of it that is soluble in water. Preventive care actions in relation to flow assurance were taken, since the suggested method uses a high volume of fresh water, increasing the hydrate risks. Scaling in wells with those characteristics was systematically removed through remote acidification (with specialized vessel assistance). That approach has shown to be always effective. On the other hand, remote acidification was always costly and dependent on the availability of critical resources. The technique depicted in this paper requires neither a vessel nor acid and, therefore, incurs significantly lower costs. The results obtained in the first tests were substantially positive since the wells’ productivity was fully restored. In this sense, the hypothesis of water solubility of the scale deposition was confirmed, and the method validated. Since its validation, the method has been applied a number of times, confirming its repeatability, and extending its use to other wells with similar scaling occurrences, reducing costs and restoring the production in a short time. Nevertheless, new challenges arise in relation to the full comprehension of the deposited material and the prevention of its deposition.

scholarly journals Irrigation with Coalbed Methane Co-Produced Water Reduces Forage Yield and Increase Soil Sodicity However Does Not Impact Forage Quality

2021 ◽  
Vol 13 (6) ◽  
pp. 3545
Author(s):  
Shital Poudyal ◽  
Valtcho D. Zheljazkov
Keyword(s):  
Fresh Water ◽  
Coalbed Methane ◽  
Produced Water ◽  
Forage Quality ◽  
Dry Weight ◽  
Quality Parameters ◽  
Forage Yield ◽  
Neutral Detergent Fiber ◽  
Forage Crops ◽  
Feed Value

The extraction of coalbed methane produces a significant amount of coalbed methane co-produced water (CBMW). Coalbed methane co-produced water is often characterized by high levels of pH, total dissolved solids (TDS), sodium (Na) and bicarbonate (HCO−3) and if used for irrigation without treatment, it may be detrimental to the surrounding soil, plants and environment. CBMW ideally should be disposed of by reinjection into the ground, but because of the significant cost associated, CBMW is commonly discharged onto soil or water surfaces. This study was conducted to elucidate the effect of the CBMW (with TDS value of <1500 ppm) at various blending ratios with fresh water on the yield and quality of representative forage crops [i.e., oat (Avena sativa) and alfalfa (Medicago sativa)]. Various blends of CBMW with fresh water reduced fresh and dry weight of alfalfa by 21.5–32% and 13–30%, respectively and fresh and dry weight of oat by 0–17% and 0–14%, respectively. Irrigation with various blends of CBMW and fresh water increased soil pH and soil sodium adsorption ratio. However, forage quality parameters such as crude protein (CP), acid detergent fiber (ADF), neutral detergent fiber (NDF), total digestible nutrients (TDN) and relative feed value (RFV) of both forage crops remained unaffected.

Optimization of Apparent Peak Viscosity in Carboxymethyl Cellulose Fracturing Fluid: Interactions of High Total Dissolved Solids, pH Value, and Crosslinker Concentration

SPE Journal ◽  
2016 ◽  
Vol 22 (02) ◽  
pp. 615-621 ◽  
Author(s):  
N. E. Pica ◽  
C.. Terry ◽  
K.. Carlson
Keyword(s):  
Carboxymethyl Cellulose ◽  
Oil And Gas ◽  
Produced Water ◽  
Ph Value ◽  
Total Dissolved Solids ◽  
Dissolved Solids ◽  
Service Companies ◽  
Polymer Loading ◽  
Crosslinker Concentration ◽  
Reducing Costs

Summary It has been common practice to use a freshwater source (either ground water or surface water) as the base fluid for hydraulic fracturing with crosslinked-gel fluids. Currently, oil and gas operators are beginning to reuse and recycle the main byproduct of oil extraction, which is produced water. However, because of the high variability of produced-water quality (temporal and spatial), and the high content of total dissolved solids (TDS), the viscosity targets for the fluid can be difficult to achieve. The research described in this paper examines the sensitivity of higher-salinity waters to several variables related to the gel-formation process. The polymer used for the gel fluid was a carboxymethyl cellulose (CMC) derivative, and zirconium (Zr) was used as the crosslinking metal. Rheology experiments were conducted at different pH values, polymer loading, and crosslinker concentrations. The outcome of this research is presented in 3D contour-peak-viscosity maps that can be used by oil and gas operators and service companies to optimize the chemicals that are applied, thus reducing costs.

Assessment of Produced Water Reinjection in a Giant Carbonate Reservoir

2017 ◽  
Author(s):  
Peng Chen ◽  
Thomas Willingham ◽  
Timothy Ian Morrow ◽  
Alunood K. Al Sowaidi ◽  
Dragan Stojkovic ◽  
...  
Keyword(s):  
Produced Water ◽  
Carbonate Reservoir

scholarly journals Improving efficiency of oil recovery and finding a source of watering in multi-zone deposits by geochemical methods of research

Georesursy ◽  
2020 ◽  
Vol 22 (4) ◽  
pp. 93-97
Author(s):  
Maria S. Shipaeva ◽  
Ilyas A. Nuriev ◽  
Nikolay V. Evseev ◽  
Timur R. Miftahov ◽  
Vladislav A. Sudakov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Produced Water ◽  
Element Composition ◽  
Geochemical Composition ◽  
Well Production ◽  
Quantitative Characteristics ◽  
Production Wells ◽  
Macro Element ◽  
Water Cut ◽  
Geochemical Studies

One of the strategic ways in the development of multilayer fields is to identify the source of water inflow into the well production and, as a result, to eliminate it with subsequent optimization of the production of non-watered formations. A method for assessing the degree of water cut in formations based on the quantitative characteristics of the composition of the produced water is proposed in this article. The study of a wide collection of produced water samples made it possible to trace the change in its geochemical composition depending on the age of formation of the reservoir in the Volga-Ural region.The microelements and macro element composition of water, as well as its isotopic composition were investigated. The water of different layers differs in some of the elements, which are called «key elements». Using the methods of mathematical statistics at 2 reservoir objects operated by a common filter, the incoming water was divided into fractions depending on the geochemical composition. It is shown which of the layers has more water out. The feasibility of carrying out these geochemical studies was confirmed by blocking one of the production wells operating in 2 layers, the most watered interval according to geochemical studies, as a result of which the water cut of the well production decreased from an average of 75% to 4% and is observed for several months, the oil production rate increased from 1–2 t/day to 2.5–3 t/day and remains at a constant level.

scholarly journals MODEL-BASED OPTIMIZATION OF CYCLES OF CO2 WATER-ALTERNATING-GAS (CO2-WAG) INJECTION IN CARBONATE RESERVOIR

2022 ◽  
Vol 15 (4) ◽  
pp. 139-149
Author(s):  
F. G. A. Pereira ◽  
V. E. Botechia ◽  
D. J. Schiozer
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Co2 Production ◽  
Co2 Injection ◽  
Optimal Size ◽  
Control Variables ◽  
Limit Values ◽  
Water Alternating Gas ◽  
Production Wells ◽  
The Impact

Pre-salt reservoirs are among the most important discoveries in recent decades due to the large quantities of oil in them. However, high levels of uncertainties related to its large gas/CO2 production prompt a more complex gas/CO2 management, including the use of alternating water and gas/CO2 injection (WAG) as a recovery mechanism to increase oil recovery from the field. The purpose of this work is to develop a methodology to manage cycle sizes of the WAG/CO2, and analyze the impact of other variables related to the management of producing wells during the process. The methodology was applied to a benchmark synthetic reservoir model with pre-salt characteristics. We used five approaches to evaluate the optimum cycle size under study, also assessing the impact of the management of producing wells: (A) without closing producers due to gas-oil ratio (GOR) limit; (B) GOR limit fixed at a fixed value (1600 m³/m³) for all wells; (C) GOR limit optimized per well; (D) joint optimization between GOR limit values of producers and WAG cycles; and (E) optimization of the cycle size per injector well with an optimized GOR limit. The results showed that the optimum cycle size depends on the management of the producers. Leaving all production wells open until the end of the field's life (without closing based on the GOR limit) or controlling the wells in a more restricted manner (with closing based on the GOR limit), led to significant variation of the results (optimal size of the WAG/CO2 cycles). Our study, therefore, demonstrates that the optimum cycle size depends on other control variables and can change significantly due to these variables. This work presents a study that aimed to manage the WAG-CO2 injection cycle size by optimizing the life cycle control variables to obtain better economic performance within the premises already established, such as the total reinjection of gas/CO2 produced, also analyzing the impact of other variables (management of producing wells) along with the WAG-CO2 cycles.

New method of controlling excessive water production in wells using induced formation damage

2015 ◽  
Vol 55 (2) ◽  
pp. 485
Author(s):  
Abbas Zeinijahromi ◽  
Pavel Bedrikovetski
Keyword(s):  
Fresh Water ◽  
Large Scale ◽  
Produced Water ◽  
Water Injection ◽  
Cost Effective ◽  
Formation Damage ◽  
Water Production ◽  
Permeable Barrier ◽  
Water Influx ◽  
Excessive Water

Excessive water production is a major factor in reduced well productivity. This can result from water channelling from the water table to the well through natural fractures or faults, water breakthrough in high permeability zones, or water coning. The use of foams or gels for controlling water production through high-permeable layers has been tested successfully in several field cases. A large treatment volume, however, is required to block the water influx that generally involves high operational and material costs. This extended abstract proposes a new cost-effective method of creating a low-permeable barrier against the produced water with induced formation damage. The method includes applying induced formation damage to block the water influx without hindering the oil production. This can be achieved by injection of a small slug of fresh water into the water-producing layer. This results in release of in situ fines from the matrix, which can decrease permeability and create a local low-permeable barrier to the producing water. In large-scale approximation, water injection with induced fines migration is analogous to polymer flooding. This analogy is used to model the fresh water with induced formation damage. Sensitivity studies showed that the injection of 0.01 PVI of fresh water resulted in the blockage of the water-producing layer and an incremental recovery by 8% in field case A, with respect to the standard production scenario. The authors found that the incremental gas recovery with induced formation damage was sensitive to reservoir heterogeneity, permeability reduction and slug volume.

Constraining the Conditions of Scale Deposition in a Gas Condensate Well: A Case Study

2014 ◽  
Author(s):  
R. A. McCartney ◽  
SPE, S. Duppenbecker ◽  
R.. Cone
Keyword(s):  
Produced Water ◽  
Gas Condensate ◽  
Flow Profile ◽  
Formation Water ◽  
Zone Formation ◽  
Water Rates ◽  
Wide Range ◽  
Management Plans ◽  
Water Saturated ◽  
Scale Deposition

Abstract Field X is a gas condensate field where the wells produce primarily gas and a small amount of formation water mixed with condensation water (&lt;19 Sm3/d per well). Unexpectedly, scale (aragonite, possibly with minor sulfate minerals) was identified in Well A during a routine PLT. To aid scale mitigation planning, the cause of scale deposition has been investigated using scale prediction software. A wide variety of data and information has been used to constrain and verify the scale predictions and as a result they are consistent with the observed type, volume and location of scale, PLT results (inflow temperature, hydrocarbon flow profile), produced water and formation water Ca and Cl concentrations, and production data (hydrocarbon and total water rates). A novel method was developed to estimate the composition of formation water entering the well from produced water analyses (mixtures of condensation and formation water) and where produced water rates are available this can also be used to estimate the rate of flow of formation water into the well. The results suggest that formation water enters the well at low rates (∼1m3) from the upper perforated zone (Formation 1) whilst water-saturated hydrocarbons enter from both the upper and lower zones (Formations 1 and 2). The formation water Cl concentration is between ∼5, 100 and ∼11, 000 mg/L and the Ca concentration may be between ∼121 and ∼177 mg/L. Partial evaporation of formation water (due to pressure decline and Joule-Thomson heating) as it enters the well causes scale deposition. The remaining formation water is produced along with water condensing from gas. An additional risk of total salt deposition in these wells was also identified. This study has shown how a wide range of data can be used to constrain the conditions of scale deposition in such wells. The results of this study are being used to develop scale management plans for the field.

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