Scale dissolvers have successfully been used to restore well productivity intwo Statfjord Field wells suffering from scale induced formation damage.Combined with scale inhibitor treatment further production loss has beenavoided. The dissolver efficiency towards BaSO4, and SrSO4, is stronglydepending on high pH (pH> 9-10) in the treatment slug. Two different scaledissolvers have been tested, and are found to have equally good performanceregarding dissolution capasities and effect on production. Well case historiesand details about job design and production data before and after thetreatments are documented. Combined scale dissolver and scale inhibitor squeezetreatment is implemented as the current scale treatment strategy for theStatfjord Field.
The Upper and Lower Brent reservoirs in the Statfjord Field are developedwith a row of sea water injectors, completed below the oil/water contact, todisplace oil up structure to the east toward a row of oil producers near thecrest of the structure. Key information about the Statfjord Field is listed intable 1.
Filtration control has a considerable impact on drilling fluid properties & performance, on drilling costs and on well productivity. The requirements for filtration control, with regard to optimisation of the various stages of drilling a well, are ambiguous. This is largely due to the lack of understanding of the functionality of the mud components and on imprecise definition of demands.
Multi-Core Dynamic Filtration equipment has been designed to study static- and dynamic filtration (including spurt loss conditions) and assess their effect on return permeability for up to 4 core samples at a time. Several core samples in one experiment will enable us to evaluate the effect of permeability variation on clean-up efficiency. In another development, equipment has been designed for continuous measurement of cake thickness during filtration.
Polymer systems have been identified that effect acceptable fluid loss without solid particle additions. Apparently, the micelles formed have the dual functionality of solids to plug the pores and polymers to reduce cake permeability. This line of investigation may have potential in the development of truly solids free drilling fluid systems based on high density brines (e.g. Formates).
Fluid loss, a key parameter in drilling fluid design
Fluid loss (control) has an effect on a number of drilling and completion parameters. It is known to have a major effect on cake properties, penetration rate and costs to name a few. It can also have a major impact on impairment of the formation. The need to evaluate the inter-dependency of the fluid loss and these parameters has long been expressed, but so far little fundamental work has been published in this field.
Research into the effects of fluid loss from drilling fluids (DF) was initiated in 1994. Initially the investigation was aimed at studying the relationship between fluid loss and impairment. It was soon realised that there were good arguments to extend the investigation to the wider field of the effect(s) of fluid loss on a number of drilling- and completion parameters. The decision was taken to design and build multifunctional experimental equipment that could be used to study a number of fluid loss related aspects of DF design. A description of the experimental equipment with some practical considerations is included.
In this paper the rationale for the fluid loss related work is given based on a review of the suggested / assumed effects of fluid loss on various drilling- and completion parameters. Further, the results of the experimental effort and the resulting conclusions are presented. This paper discusses the "mechanical" DF properties; physico-chemical properties (chemical composition), very relevant for e.g. shale stability and clay "swelling" effects, are not discussed.
This paper presents the results of a study of sludge formation from thereaction of "real-world" hydrochloric acid with several crude oils.Dissolved ferric iron has previously been shown to be a major factor in thegenesis of sludges in acidizing treatments. This work compares the sludgeabatement capabilities of a novel iron reducing agent with those of severaliron control agents in common use in the oilfield. Simple tests based onestablished API procedures are used. Results of field treatments using the newreducing agent are included.
The reaction of common oilfield acids in their pure state with components ofsome crude oils to produce insoluble solids known as sludge has long beenrecognized as a significant obstacle to successful acid stimulation in manygeographic areas. Chemical technology has been available for many years toaddress the problems of less-than-optimal production stimulation caused by thissludge formation. The American Petroleum Institute recommends an "acidsludge test," distinct from emulsion testing, to evaluate chemicalanti-sludging agents. These materials are often based on dodecylbenzenesulfonic acid (DDBSA) or its derivatives; they frequently give excellentresults in the API test, even with difficult-to-treat oils such as thenotorious light, asphaltic oils from Alberta.
Another chemical problem in acidizing, first recognized in the 1930s, comesfrom dissolved iron (particularly when in the ferric, or Fe+3, state) in theacids reaching the formations to be stimulated. The true nature and severity ofthe problems caused by dissolved iron, however, was not widely appreciateduntil the mid-1980s when some significant papers were published dealing withtwo distinct facets of the issue.
Coulter and Gougler, in 1984, reported a field investigation whichdocumented very high levels of iron in hydrochloric acid "as delivered"to the zone to be acidized in a typical acid treatment. They showed that themajor source of this iron is the tubular goods in the well. The chief concernexpressed in their paper, as well as in the patent literature of around thattime, was in preventing precipitation of inorganic ferric iron compounds, suchas ferric hydroxide. This precipitation is well known to occur as acid spendsto a pH of around 2, and was widely held to be the major mechanism of formationdamage attributable to iron. Many systems to suppress iron solids depositionwere then, and are still, in use. Most depend on chelation or reduction offerric iron as the acid spends toward and past this pH value.
SPE 31077 Optimizing Stimulation Treatments of Gravel Packed Wells by Analysis of Back Produced Fluids After Stimulation Terje Schmidt, SPE, Statoil, Torstein Haugland, SPE, Statoil, Jan Tuxen Thingvoll, Vestlandsforsking Copyright 1996, Society of Petroleum Engineers, Inc.
A significant loss of productivity was observed in some of the first high rate gravel packed wells on the Gullfaks field. Productivity was initially restored by stimulation with clay acid (HBF4) and mud acid (HF/HCl) to remove and dissolve formation damage, believed to be caused by fines and clay. However, productivity soon decreased and frequent treatments with diluted HCl were necessary to maintain production from these wells.
The paper discusses mechanisms that can contribute to the observed permeability reductions following shortly after each treatment.
Evaluation of the HCl treatments revealed that large amounts of "AlF", "FeF" and CaF2 compounds, had formed as a result of the initial clay acid treatments. In one well, significant amounts of re-precipitated compounds of Al and Fe that could be attributed to the first acidizing job were detected up to 2 years later. Finally, the paper discusses how the treatments can be optimized based on the resulting increase in production rates and the chemical pattern revealed after stimulation
The Gullfaks Field is located in the central part of the East Shetland Basin in the Northern North Sea (Fig. 1). The field is operated by Statoil on behalf of the Production License 050 consisting of Statoil (85%), Norsk Hydro (9%) and Saga Petroleum (6%). The field is developed with 3 Condeep platforms. Gullfaks A, B and C, and has been on production since December 1986. Current production is approximately 90 000 Sm3/D from 70 production wells, and approximately 60% of the 280*106 Sm3 recoverable reserves are produced. Estimated production life for the field, based on own reserves, is 20 years with peripheral water injection as the main drive mechanism.
The oil is located within three major sandstone units. the Brent Group, the Cook Formation and the Statfjord Formation. The Lower Brent, comprising of the Broom, Rannoch and Etive Formations represents a prograding delta front. The upper Brent is comprised of the Ness and Tarbert formations. The Ness Formation represents a delta top sequence with minor mouth bars dominating, while the Tarbert Formation represents the retrieving delta front building a homogenous sandstone unit on the top.
The reservoirs are overpressured, with an initial reservoir pressure of 310 bar at datum depth (1850 m below mean sea level), and a temperature of around 70 C. The oil is undersaturated with a saturation pressure around 245 bar varying with depth and location.
All Gullfaks formations contain poorly consolidated sands with high porosity and a potential need for sand control. Until May 1989, sand strength prediction and selective perforation was the main strategy and considerable research was conducted to avoid sand production. In a number of wells, water break through caused severe temporary reduction of maximum sand-free rate, and the need for sand control was clearly realized.
Since then, remedial action for sand control has been implemented in a total of 47 wells. Out of these, 30 are cased hole gravel packs and two are open hole completions (Fig. 2). With the exception of the first wells to be gravel packed, the gravel packed wells have performed very well, with no significant productivity decrease before sea water breakthrough and scaling problems occurred. This paper will concentrate on the experience with some of the relatively few wells that have needed regular acid treatments to maintain productivity; A-16A, A-23 and B-9 and where loss of productivity was not caused by scale. P. 41
The critical salinity concentration (CSC) was used to compare the ability ofnonionic polyacrylamides (PAM) and cationic polyacrylamides (CPAM) to stabilizemontmorillonite clay dispersed in sandpacks. The method consists of injectingbrine at decreasing salinity levels until clay release is detected by acontinuous increase in pressure drop.
As expected, because of the neutralization of negative clay surface chargesby adsorbed macromolecules, CPAM have a higher stabilizing power than PAM,lowering the CSC of NaCl from 27 500 to only 500 ppm, and the CSC of KC1 from5000 to 1000 ppm. However, because of their ionicity and very high adsorptionlevel, CPAM strongly reduce sandpack permeability. Likewise, alow-molecular-weight PAM may be preferred because of its good stabilizing powerassociated with a minimal loss of core permeability.
In a preceding paper, we evaluated the ability of different polymers widelyused in the oilfield industry to stabilize montmorillonite clay dispersed insandpacks. The method designed to run the stability tests, namely the criticalsalinity concentration (CSC) method, consisted of injecting brine at a widerange of injection rates with decreasing salinity levels until pressure did notstabilize anymore because of clay release in the sandpack. The CSC is thelowest salinity tolerated before clay release. The tests were run first withoutany polymer, then, in the same experimental conditions, after polymeradsorption. The stabilizing power of a given polymer was quantified by thereduction in the CSC value obtained after polymer adsorption in the pack.
Among the different polymers tested, xanthan gum and carboxymethylcellulosewere found to have almost no stabilizing power. Scleroglucan was found to havesome stabilizing properties, although much less than nonionic polyacrylamidesPAM). Indeed, after PAM adsorption in the sandpack, the CSC of NaCl droppedfrom 27 500 to 6500 ppm and the CSC of KC1 dropped from 5000 to 1500 ppm.
The mechanism involved in the polymer stabilizing effect is the coating ofpore walls by adsorbed macromolecules, which both inhibits clay swelling tosome extent and prevents clay release and migration (Fig. 1).
Completion scenarios and knowledge of formation damage distribution are keyfactors that determine the success of horizontal well applications. In a bottomwater drive reservoir the completion scenario should be selective because asignificant portion of the horizontal well section would not be productive atlate production period. A simple correlation to estimate pseudoskin factors dueto partial completion for a horizontal well is provided. When water or gasconing is not expected, distributed perforation intervals in a damagedformation yield the highest productivity.
Horizontal wells become popular in the last decade for exploiting more oilfrom the reservoirs. The applications range from extracting attic oil andultra-thin oil column to developing a marginal oil field. There are of coursemany other horizontal well applications for improving productivity of variousreservoirs. As the technology is relatively new, the reservoir fluids flowbehavior is not fully understood. Many researchers have devoted their effortsto come up with results which undoubtedly contribute to both practicalconsideration and the actual operations. It is the facts, however, that some ofhorizontal wells already implemented were not as good as expected in theirperformance. There might be situation beyond expectations that caused theimplementation technically and/or economically unsuccessful. Probably, poorreservoir description including geology and fluids distribution and formationdamage due to drilling and completion fluids have resulted in poor performance.Refs. 8 and 9 provide guides in terms of interdisciplinary concepts forhorizontal well applications.
Complex mechanism of fluids flow in a reservoir system producing the fluidsthrough a horizontal and in the wellbore itself have been challenging toresearchers in petroleum industry. Many studies have been focused on thewellbore hydraulics. The implication is that if the pressure losses in thewellbore is greater than ten percents of the drawdown then the inflowperformance may be considerably affected. Most of these efforts, however,involved single phase flow in the reservoir, assuming the same specificproductivity index at any point along the wellbore. Several papers dealt withwellbore/reservoir interactions for two-phase flow situations. Otherresearchers emphasized their works on inflow performance relationships (IPRs)for solution gas drive horizontal wells. Unlike for vertical wells, no attempthas been made to generate damaged and stimulated dimensionless IPR curves forhorizontal wells.
Nonionic surfactants are commonly used during well stimulation for several reasons. They reduce interfacial tension between the acid and oil phases, thus improving acid/rock interaction. They are also used to form a stable foam which improves the sweep efficiency during acidizing. However, these surfactants should be employed at temperatures below their cloud point (defined as the temperature at which the surfactant solution becomes cloudy). This temperature signifies the onset of the surfactant salting out, which will reduce the efficiency of the stimulation and may damage the formation.
An experimental study was conducted to assess the effect of various acids and stimulation additives on the cloud point of nonionic surfactants. The influences of acids (inorganic and organic), mutual solvents, friction reducers, hydrogen sulfide scavengers, sequestering agents, short chain alcohols, simple salts, scale inhibitors, anionic surfactants on the cloud point of several nonionic surfactants were examined over a wide range of parameters.
The results indicated that the cloud point monotonically increased with the acid concentration. However, the rate of increase depended on the acid type and the number of ethylene oxide groups of the surfactant. Salts depressed the cloud point of nonionic surfactants at all hydrochloric acid concentrations examined. Alcohols, methanol and isopropanol enhanced the cloud point of nonionic surfactants. The effect of mutual solvents was found to be a function of the number of ethylene oxide groups of the surfactant, acid and mutual solvent concentrations. Anionic surfactants depressed the cloud point of nonionic surfactants at all sodium chloride concentrations examined. Clay stabilizers (cationic polymers) and hydrogen sulfide scavengers depressed the cloud point whereas scale inhibitor and phosphonic acid did not affect the cloud point significantly.
It is extremely important to measure the cloud point of nonionic surfactants before performing a stimulation job. It is also recommended to use the acid formulation and mixing waters that will be used in the field.
Well stimulation is a process aimed at the removal of near-wellbore impairment due to deposition of particulate solids during drilling, workover or production operations.1,2 In this process an acid or mixture of acids is injected into the well to dissolve and remove this damage. Apart from removing deposited material, the acid can react with the rock matrix and enlarge pore sizes.3 This will allow insoluble fines to be flushed out when oil production is resumed (producing well) or during backflow (injection well). Enlarging pore sizes will improve the permeability in the wellbore area, hence the productivity or injectivity of the well will improve.
The primary objectives of a gravel pack are preventing formation sand production, achieving high productivity, and providing completion longevity. For cased hole completions, inadequately filling the perforation tunnels with gravel is probably the main cause of formation damage which ultimately translates into a well that is completion limited since it produces below the capacity of the reservoir. Hence, performing prepacking operations that fill the perforations with undamaged gravel will usually enhance productivity. Aside from prepacking, effectively packing the casing-tubing annulus produces a stable, void-free gravel pack that will not settle or deteriorate with time.
Gravel pack procedures were developed in the mid-1970's and subsequently optimized to address the above concerns. They consisted of preacidizing (if required) the formation followed by a prepack performed with lightly-gelled water pumped at matrix rates that filled the casing with gravel to the top of the perforations. After washing the prepack gravel from the casing, the gravel pack assembly was run and an annular gravel pack was performed using water as the transport fluid. This procedure provided two opportunities for gravel to prepack the perforations. Acidizing was subsequently performed to achieve the desired productivity. Well test data show that over 70% of the wells tested had skin factors that were less than 10 and many were in the zero range. Gravel pack failures were rare and over 95% of these completions produced to depletion without requiring a workover.
More recently, enhanced prepacking has been performed by pumping at high rates and using water as the transport fluid. These treatments were designed to fracture the formation a distance of 5-10 ft from the well to bypass formation damage. The high rate prepacks have been performed with either the screen in place (single step) or prior to running the screen (two-step) in the well. In either case, the annular pack continued to be performed with water. The high rate completions have been performed at little or no incremental cost compared to those conducted at matrix rates since they were performed with platform-based, moderate horsepower equipment. The performance of these completions has been excellent. The need for post-completion acidizing and associated flowback concerns has been virtually eliminated. Wells clean up more rapidly, consistently have higher productivities, and appear to have improved completion success as compared to those performed at matrix rates.
A myriad of procedures have been developed for gravel packing wells. The technique used is normally the consequence of operating conditions, economic constraints, personal preferences, and other reasons. An ideal gravel pack is one that yields the highest productivity, longest completion life, and controls the entry of formation sand into the well for the lowest cost. To achieve these objectives, procedures must be effective, as simple as possible, and field worthy.
Wenrong, Mei (Southwest Petroleum Institute) | Shihong, Shu (Southwest Petroleum Institute) | Tianhua, Lai (Southwest Petroleum Institute) | Wenzhong, Liu (Sichuan Petroleum Administration) | Guoheng, Hu (Tuha Oilfield)
To a great extent, experiment selection of temporary plugging particles(TPP) in the temporary plugging techniques (TPT) is blind at present. Based on the investigation of particle migration, deposition and plugging mechanism in the porous media, network model, the inter-connected pore and throat network on the basis of reservoir pore structure, is applied to the optimization of TPP in the TPT. It is shown that the result of simulation has a good agreement with that of core fiooding experiment and can be used to guide the study of core flooding experiments. The main advantages of this method are: 1. the model can be repeatedly used many times and can be used in the simulations of various purposes and aspects; 2. the results are highly comparable by the simulation while much less by the core flooding experiments.
It's well known that formation damage existing extensively in each phase of field operations is a difficult problem in the petroleum industry, and can not only damage oil and gas resources and considerably reduce the productivity of hydrocarbon reservoirs, but also even kill hydrocarbon reservoirs, and therefore cause a very great waste of manpower, material and financial resources. During the past several decades, beginning with our original consciousness of formation damage problem, unremitting efforts and a great number of researches have been made from the understanding of formation damage mechanism in the past to the controlling and preventing of formation damage by using various methods at present.
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.
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).
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.1 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 be
loss of workover fluids
residue from acid treatments3