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Results
Abstract The evaluation of a present acid injection profile used in acid flowback analysis is an important tool for optimizing acid treatments, as it affects the acidizing process by improved results of hydrocarbon production rather than subjecting the well to yet another optimized acid treatment in the future. In the standard method of acid flowback analysis, the engineers interpret the plots of the return fluid ionic content versus return volumes at certain increments i.e. every 10-20 bbl. In our work. we have found that this method may pose more questions than it answers. In order to simplify the acid flowback analysis method and provide a more definitive interpretation. we introduced a simple derivative technique in the analysis of the dissolved formation or the scale dissolved ionic content. In this technique the ratio of incremental ionic concentration per incremental produced volume (the derivative) was plotted against the cumulative produced volume. The significance of using this technique is that the derivative of ionic concentration with respect to the produced volume is very sensitive to the minute changes in the ion concentration per unit volume or cumulative acid flowback volume. We applied our method to two wells, which we shall call them wells # 1 and#2. In the case study of well # 1, first we found that the acid stimulation treatment dissolved significant amounts of material containing Potassium, Sodium. Magnesium, Iron, Aluminum, Silicon, Barium. and Calcium. But the treatment did not remove the Zinc completely. The source of Zinc could have been either the formation of zinc hydroxide from heavy brines or the 60% Zinc content of some pipe dopes. Incomplete dissolution of material containing Zinc resulted in an inefficient treatment. Consequently, the treatment was able to restore only the original production rate but failed to result in any increase in incremental production. Secondly. from the disordered dissolution profiles of Magnesium, Calcium and Barium, we found that these three elements existed in the formation as individual mineral rather than scale.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.48)
- Well Completion > Acidizing (1.00)
- Production and Well Operations (1.00)
Abstract During petrophysical and petrographical analyses of the core plugs, generally, we pay close attention to the "fines migration" when we observe kaolinite minerals filling the pore space or lining the pores. The conditions leading to a drastic reduction of permeability (formation damage), at low temperature, by kaolinite have been documented in the literature:to depend on the colloidal and hydrodynamic forces far from and near the well bore respectively and to mechanically bridge the pore throats. And, at high temperature like in steam flooding, the formation damage caused by kaolinite depends on (1) water chemistry i.e. ionic content. (2) pH of the injection water. and (3) low salt concentration. Although these mechanisms provide a general knowledge base to control the formation damage by controlling the kaolinite particles we found no clues as to what changes occur in the kaolinite morphology or mineralogy. The case in point is a Tuscaloosa sand core from central Louisiana while being drilled with a high pH fluid i.e. pH=10–12 with caustic soda. In order to understand and therefore to control the formation damage due to kaolinite migration, we subjected a series of core plugs prepared from a Tuscaloosa sand conventional core to a low temperature, high simulated spurt loss (flow rate of 11.1 cc/min) for a short period of fluid/rock contact time (45 minutes). After a thorough petrophysical analysis. we found that within this short period of contact time between the rock and fluid at pH=10-12 at low temperature, the permeability of cores decreased considerably. The petrographical analysis of the same cores revealed that the reason for this drastic change in permeability was the onset of the conversion of kaolinite to halloysite and dickite under the oxidative effects of Sodium Peroxide. Also, the amphoteric nature of kaolinite similar to Al(OH)3 i.e. dissolution of kaolinite in both acids and bases, plays an important role in its solubility in caustic soda at pH=10-12. On the basis of our findings we concluded that in both field and laboratory coring and/or drilling the Tuscaloosa sand or possibly any other sand with a high kaolinite content (greater than 5%) the best conditions for controlling the formation damage are to keep the pH of all injection fluids in a buffered and well controlled state of near neutral and/or to control the filtrate to near zero in such sensitive formation. Introduction Most, if not all, laboratory analysts, upon observing kaolinite mineral in the pore space of the side wall or conventional cores, conclude that the main cause of a possible formation damage (decrease in permeability) could be attributed to the migration of "fines" within the pores or pore throats. Pursuing the matters further, the analysts conduct a series of core flow tests in order to document the magnitude of damage to permeability and other visual observations. One of these visual examinations. in the case of a "caustic flooding" project encompassing a comprehensive laboratory and field work, reported some white particles looking like kaolinite plugged some Berea cores in the lab tests. The Berea cores contained about seven percent kaolinite clay. Also, the same kind of whitish fine material showed up in the surface facilities in the field and was believed to be kaolinite plugging the gravel pack and the screen. Although the process of steam flooding (Huff and Puff) was successful in the field, the parties involved did not get a chance to examine thoroughly the "whitish fines" showing up in the surface facilities of the caustic-steam flooded well drilled near the above mentioned well. In short, if there was any problem with the caustic flooding in terms of fines migration and/or formation damage, neither was it understood nor remedied.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Abstract The Wilcox reservoir in South Central Louisiana's Reddell Field has responded quite favorably to slow-reacting HF acid treatments. A historical perspective, dating back to 1981, is the basis for the comparison of traditional HF acid (12% MCI - 3% HF) systems to that of the slow-reacting HF acid system. These documented benefits are listed below:Two- to four-fold production increase Accelerated recovery of well production Reduced workover fluid recovery time from 24 months to 2 months Increased success rate associated with stimulation from 40% to 90% The improved performance was achieved because of careful attention to reducing chemical incompatibilities. Separation of the HF fluids from the potassium chloride workover fluids and the proper choice of HCl-HF concentrations for the Wilcox formation mineralogy dramatically reduced secondary plugging from the HF treatment. This paper discusses Wilcox formation mineralogy and its susceptibility to formation damage. In addition, the paper compares conventional acid treatments to slow-reacting HF acid treatments. Finally, criteria are suggested regarding applications of HF acid for similar formations. Introduction Reddell field is located 90 miles north of Lafayette, LA. The field was originally discovered by Inexco Oil Company in 1970 with the drilling of the Pardee No. 1. The field was ultimately developed with the drilling of 18 wells, 15 of which proved to be successful. A maximum rate of 40 MMcf/D and 2,500 barrels of condensate per day (BCPD) was obtained in early 1973. Currently, the field produces 12 MMcf/D and 300 BCPD from 22 completions in 15 wellbores. To date the field has produced 168.9 Bcf and 6.5 million barrels of condensate (MMBC). Reservoir Characteristics Gas is produced from three broad units in the Wilcox sand. Sand conditions are fairly consistent and uniform throughout the 15 producing wellbores. The Wilcox formation is fairly tight, with permeabilities to gas ranging from 0.5 to 2 md. Porosities have been measured at 12 to 18% with water saturations averaging about 40%. The primary mineralogical component of the reservoir is quartz (Table 1). In addition, a large portion of the matrix is comprised of feldspar, pyrite, and clay. Each of these minerals plays an important role as service company designers are selecting the appropriate acid systems and acid concentrations for stimulating the formation matrix. The type of clays contained within the matrix greatly affect the nature of the damage and subsequently, the design of the stimulation treatment. Three primary clays are found in the Reddell field: chlorite, kaolinite, and illite (Table 2). The fact that these clays coat the sand grains contributes to the extreme sensitivity of the Wilcox sand. Causes of Formation Damage The four primary causes of formation damage in the Wilcox sand in Reddell field are considered to beclay swelling fines migration loss of workover fluids residue from acid treatments
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Well Drilling > Formation Damage (1.00)
- Well Completion > Acidizing (1.00)
- Production and Well Operations > Well Intervention (1.00)
- (3 more...)
Analysis of Skins and the Performance of Gravel-Packed Completions in Oil and Gas Wells
Okoye, C.U. (University of Southwestern Louisiana) | Suriyakriangkai, S. (University of Southwestern Louisiana) | Ghalambor, A. (University of Southwestern Louisiana) | Alcocer, C. (University of Southwestern Louisiana)
Abstract This paper presents solutions and analysis of mathematical model of skins due to completions in gravel packed oil and gas wells. The models can bedivided into three cases:Open Hole gravel packed well Cased-holeperforated gravel packed well Collapsed perforation tunnel gravel packed well. The skins due to completion include damaged skin, restricted entry skin, liner skin, gravel packed sand skin, slanted well skin, perforation geometry skin, crushed zone skin, non-darcy skin and the skin in the perforation tunnel. The results obtained from the calculation in open hole gravel packed show that the skin in damaged zone decreases as the damaged zone permeability increases. For the cased-hole perforated gravel packed oil and gas well, the results show that increasing the perforation radius, perforation length and crushed zone permeability result in the decrease of crushed zone skin for both darcy and non-darcy flow, the perforation geometry skin and skin in the perforation tunnel for both darcy, and non-darcy flow for a given shot density. For the collapsed perforation tunnel gravel packed oil and gas well, the results show that the increasing perforation radius results in the decrease of hemispherical flow geometry skin and skin in the perforation tunnel for both darcy and non-darcy flow for a given shot density. The solutions of each gravel packed skin model is used to analyze field and experimental data in order to estimate the skins and the decrease or increase in productivity ratio due to completions in gravel packed wells. Introduction Gravel pack is a common sand control technique used in many formation with unconsolidated or poorly consolidated sands. As a sand control treatment gravel pack has been used to exclude sand from the production well and hence the produced fluid in the Gulf of Mexico for over 50 years. Sand production can often be readily achieved by proper sizing of the gravel with respect to formation sand size using well established rules. Sometimes well consolidated formations can produce sand and hence gravel pack is employed in such formations for sand control. Gravel pack completions are normally of three types namely:openhole, cased hole and collapsed tunnel. The open hole gravel pack is used when the completion is in a consolidated single sand. or when multiple consolidated sands can be produced without fear of gas or water production. The cased hole and collapsed tunnel gravel packed completions require perforation and are often used in unconsolidated and poorly consolidated sands or when multiple sands are produced through tubing string.
- North America > United States > Louisiana (0.46)
- North America > United States > Texas (0.28)
- Asia > Brunei > Seria Field (0.99)
- North America > United States > Texas > East Texas Salt Basin > Hawkins Field > Woodbine Formation (0.93)
SPE Members Abstract A laboratory study was conducted to evaluate formation damage due to steam injection. The investigation includes the adsorption and desorption of divalent ions and the transportation of scales through the formation. Several displacement tests were made at different elevated temperatures (200 degrees F to 500 degrees F) and steam salanity or alkalinity to determine the rate and nature of formation damage during steamflooding. Other tests conducted in this study include; roller oven tests, SEM EDEX and petrographic studies. The results from this study show there is decline in the permeability when temperature permeability when temperature and alkaline concentrations are increased. It was also observed that the alkaline solution PH decreased with increase in temperature. SEM, X-Ray, EDX and petrographic analysis show petrographic analysis show pseudo-hexagonal stacks of pseudo-hexagonal stacks of mineral overgrowth which blocked the pore throats. There was dissolution of minerals and precipitation of aluminosilicate such as zeolite. This study provides screening procedure for estimation of potential formation damage due to steam injection. Also, the results obtained in this study relate to actual formation during steam cyclic steam and direct steam injection. Introduction In order to understand the theory of reaction kinetics related to this experimental investigation, it is necessary to look at the physio-chemical aspects of reaction kinetics.
- North America > United States > Louisiana (0.46)
- North America > United States > California (0.28)
- Geology > Mineral > Silicate (0.98)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.88)
- Geology > Geological Subdiscipline > Petrology > Petrography (0.65)
Abstract Enhanced oil recovery processes can lead to severe and permanent reductions in permeability due to interactions between injected fluids and reservoir rock. This is true particularly in high clay content and poorly consolidated reservoirs. Near wellbore permeability damage was suspected as a factor permeability damage was suspected as a factor contributing to post injection production decline observed during high PH cyclic steam injection at Bayou Bleu field. This paper presents the laboratory studies undertaken to evaluate the influence of injection fluid composition, temperature, mineralogy and flow rate on permeability damage. The degree of damage during steam injection was observed to be dependent on PH, rock clay content, temperature and injection rate. Permeability reduction of up to 37% was observed in some cores at varying temperature and PH values for flow test and up to 70% for Rolling PH values for flow test and up to 70% for Rolling Oven test. Partial permeability restoration was obtained in all cases by reversing the direction of steam injection in the cores. Sandstone interaction with high PH steam leads to incongruent dissolution of clay minerals and subsequent precipitation of new aluminosilicates. Steam with caustic soda additive precipitated crystalline zeolite between temperatures precipitated crystalline zeolite between temperatures of 100 degs and 300 degsF, mixture of zeolites and amorphous compound between 300 degs and 400 degs F and amorphous precipitate between 400 degs and 500 degs F. Mechanical fine migration and hydrothermal effects constitute the primary damage mechanisms when low PH steam is injected into Berea sandstone. The permeability damage due to fine migration was found to be rate sensitive while the damage caused by hydrothermal effect increased with increasing temperature. For high PH steam the primary damage mechanism is chemical dissolution and precipitation of aluminosilicates. The complex chemical activities were found to be temperature and alkali concentration dependent. While increasing temperature and alkali concentration generally increased the dissolution process the precipitation of certain aluminosilicates process the precipitation of certain aluminosilicates (zeolites) are inhibited at high temperatures and alkali concentration leading to improved permeability. SEM analysis revealed that the permeability. SEM analysis revealed that the precipitates clogged pore spaces and plugged pore precipitates clogged pore spaces and plugged pore throats. High flow rate reduced the amount and rate of precipitation but at field scale flow rates the precipitation rate was high enough to cause rapid precipitation rate was high enough to cause rapid permeability reduction. permeability reduction Introduction Wellbore damage due to plugging or resulting from erosion of the formation and gravel pack because of silica dissolution has been a serious concern plaguing steam flooding and alkaline flooding plaguing steam flooding and alkaline flooding particularly at elevated temperatures. Effluents particularly at elevated temperatures. Effluents from steam generators often have PH values above 12 due to the use of high bicarbonate surface waters as feeds. Injection of high PM waters especially at elevated temperatures causes expansion and dispersion of water-sensitive clays and solubilization of silica and aluminum minerals. The hydroxide and carbonate ions in the effluents react with magnesium, calcium and other salts in the formation rock and fluids to generate precipitates. Steam injection in heavy oil reservoirs produces hydrothermal reactions which has been recognized as a source of permeability decline resulting in wellbore damage even in unconsolidated formations. Previous investigator have shown that salinity, flow rate. PH and temperature are the main contributing factors. PH and temperature are the main contributing factors. During alkaline flooding and its variations alkaline chemicals will react with reservoir rock and fluids to produce precipitates. Factors such as PH, temperature, flowrate, ionic makeup of the rock and reservoir fluid and to a lesser degree pressure will determine how such scales form. *****NO PAGE #
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.91)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
The Effect of Temperature on the Size Stability of Conventional and Ceramic Gravel Packs
Alcocer, C.F. (U. of Southwestern Louisiana) | Toups, M.M. (Marathon Oil Co.) | Hayatdavoudi, A. (U. of Southwestern Louisiana) | Ghalambor, A. (U. of Southwestern Louisiana) | Okoye, C. (U. of Southwestern Louisiana)
Abstract Laboratory research was performed to study materials used in grovel packs. There were conventional quartz sand and ceramic pellets. The main objective of this research was to determine the effects of elevated temperatures on the size and shape of subject materials. specifically as related to the generation of fines within the gravel pack itself. Also, the feasibility of using ceramic pellets versus conventional quartz gravel as pack sand material was investigated. These objectives were achieved by examining 20/40 and 40/60 mesh samples of subject materials for the influence of various temperatures (room temperature up to 550 degrees F) on particle size distribution, grain surface degradation, mechanical strength, permeability and conductivity stability, and fracture limits. SEM photograhs of 40/60 mesh gravel indicated an increased amount of pits caused by temperature. Also, the formation of striations and/or flaking were present on the 40/60 mesh gravel. The crush test present on the 40/60 mesh gravel. The crush test performed at 10,000 psi on the 40/60 mesh gravel performed at 10,000 psi on the 40/60 mesh gravel produced fines in excess of 25% by weight. The 20/40 produced fines in excess of 25% by weight. The 20/40 and 40/60 mesh ceramics and 20/40 mesh gravel displayed a decrease in permeability with increasing temperature. A linear regression analysis was performed. Based on this study, the ceramics appear to be best suited for gravel pack material at elevated temperature. Even though both gravel and ceramics produced fines, the ceramic grains are able to withstand much higher pressures and stresses coupled with higher temperature. pressures and stresses coupled with higher temperature Introduction Most thermal recovery operations are designed for formations that are classified as unconsolidated and that require some form of sand control. With high temperatures, thermal stresses are generated that can cause fracturing to occur in the formation and gravel pack sand grains. The action of these thermal stresses in conjunction with shear stresses due to fluid movement can result in even smaller sand grains or "fine" to be produced. The ultimate result of the generation of fines is a reduction in permeability which consequently reduces or even halts production. The main objectives of this research work was to perform a laboratory study aimed at determining the effects of elevated temperatures on the size and shape of the sand used in the pack. Also, the feasibility of using ceramic pellets versus pack. Also, the feasibility of using ceramic pellets versus conventional gravel as the pack sand was investigated. Ceramic pellets are currently being used as proppants in hydraulic fracturing. They were developed with high strengths in order to withstand high downhole temperatures without dissolution or size reduction of the grains. To achieve the main objective of this study, a comparison of both ceramic and gravel sands over a range of temperatures (200 degrees F, 400 degrees F and 550 degrees F) were performed. The following aspects of each sand were investigated:The reduction in the size distribution of the sand after being subjected to temperature. The generation of fines. A visual inspection of the grain surface before and after temperature effects using a scanning electron microscope. Reduction in the permeability of the sand due to temperature i.e. absolute permeability and conductivity of 20/40 gravel and ceramic. The strength of the materials using an MTS (Material Testing System) machine which measures the load at failure. Establishing a correlation between time, temperature, grain size and permeability of gravel and ceramic through linear permeability of gravel and ceramic through linear regression analysis. LITERATURE REVIEW The effectiveness of using ceramic proppants versus gravel proppants in hydraulically fractured stimulation treatments for oil and gas wells have been documented. P. 47
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.48)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (0.45)
- North America > United States > Texas > Anadarko Basin (0.99)
- North America > United States > Oklahoma > Red Fork Channel Sand Formation (0.99)
- North America > United States > Oklahoma > Anadarko Basin (0.99)
- (2 more...)
Abstract One of the known causes of formation damage in producing wells is through the plugging of the producing wells is through the plugging of the formation by microorganisms. The result of the formation plugging will be a reduction in permeability. There is no effective means to date that can effectively deal with this type of formation damage; which can occur during drilling, completion, or secondary recovery operations. The biocide treatment used in waterflood operations is only effective in killing the microorganisms that are in the water prior to pumping it down the hole, but it will not be pumping it down the hole, but it will not be effective as far as the future growth of the microorganisms is concerned in the formation. A series of experiments were conducted using cores of Berea sandstone. The permeabilities of the cores were determined after preparation. The cores were then injected with micrococcus luteus bacteria at several different pressures. The permeabilities of the cores were determined again by the same technique under the same conditions. A 50% to 75% decrease in permeability was resulted from bacterial injection permeability was resulted from bacterial injection (depending on whether the core was cut horizontally or vertically along the formation bedding plane). The cores were examined with a scanning electron microscope (SEM). The SEM study showed that the pore sizes ranging from 0.4 to 10 microns were pore sizes ranging from 0.4 to 10 microns were seriously plugged by the microorganisms. The damage was minimal for the pores larger than 50 microns. The cores were then injected with various volumes of a 2% concentration of oxidizers at several different pressures. The two oxidizers used were sodium pressures. The two oxidizers used were sodium hypochlorite and potassium hypochlorite. The results of flushing the cores with an oxidizer was partial restoration of the original permeability. partial restoration of the original permeability. Depending on the core sample, the permeability of the damaged cores was improved by 3% to 25% for the rate of treatment in the study. In the last phase of the study, corrosion tests were conducted. The results of the corrosion test showed that for the same time of exposure of corrosion coupons to the oxidizers, the amount of corrosion was found to be higher than the amount of corrosion for a drilling or some packer fluids. The exposure time of an oxidizer in a field application will be much less than the exposure time of drilling or packer fluids, and therefore, the corrosion for the oxidizer can be considered as insignificant. Introduction Formation damage by bacteria has been recognized through the work of many investigators. Bacteria are generally fed into pore spaces of the productive formation by waterflooding operations and productive formation by waterflooding operations and those organisms carried by drilling fluids. Adverse effects are recognized through reduction of the permeability of the formation where the formation permeability of the formation where the formation acts as a filter, trapping bacteria in the pore spaces. The results, needless to say, is a decline in the rate of oil production. In one study, the rate of penetration of bacteria through Berea sandstone cores was found to be independent of permeabilities above 100 millidarcys, but rapidly permeabilities above 100 millidarcys, but rapidly declined for permeabilities below 100 millidarcys. The microorganisms found in waterflood injection waters, or isolated from recovered cores, are usually of the single cell type ranging in size from 0.4 to 4 microns. Pore spaces generally found in Berea sandstone are from submicrons to approximately 100 microns. It is believed that microorganisms reduce permeability by two mechanisms. First, the live or permeability by two mechanisms. First, the live or dead cells plug pore spaces due to accumulation or multiplication. Secondly, the secretion of bacterial byproducts, such as iron bacteria which accumulates ferric hydroxide (Fe(OH)3), slime-forming bacteria, and sulfate-reducing bacteria causes plugging. The second mechanism is as harmful as the first one. In the case of sulfate-reducing bacteria, not only are they corrosive to tubular steel used in wells, but through their reactions they produce a source of energy for themselves. P. 113
- North America > United States > West Virginia (0.66)
- North America > United States > Pennsylvania (0.66)
- North America > United States > Ohio (0.66)
- North America > United States > Kentucky (0.66)
- Geology > Mineral (0.86)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Bacteria (0.74)