Jordan, M.M. (Heriot-Watt University) | Sorbie, K.S. (Heriot-Watt University) | Graham, G.M. (Heriot-Watt University) | Taylor, K. (Shell Exploration and Production (Aberdeen)) | Hourston, K.E. (Total Oil Marine (Aberdeen)) | Hennessey, S. (LASMO North Sea (Aberdeen).)
SPE 31125 The Correct Selection and Application Methods for Adsorption and Precipitation Scale Inhibitors for Squeeze Treatments in North Sea Oilfields M.M. Jordan, SPE, K.S. Sorbie, SPE, G.M. Graham, SPE, Department of Petroleum Engineering, Heriot-Watt University, Edinburgh, U.K., K. Taylor, Shell Exploration and Production (Aberdeen), K.E. Hourston, SPE, Total Oil Marine (Aberdeen), and S. Hennessey, LASMO North Sea (Aberdeen). Copyright 1996, Society of Petroleum Engineers, Inc.
Over the past three years, the Oilfield Scale Research Group at Heriot-Watt has conducted a number field studies to evaluated scale inhibitors for both downhole squeeze application and topside continuous injection for a number of North Sea operating companies. This paper presents an approach for screening commercial sulphate and carbonate scale inhibitors for field application. The screening results, which include data from static/dynamic inhibitor efficiency. static adsorption, compatibility and thermal stability are used to rank the performance of commercial scale inhibitors. From this short list, a small number (1 to 3) candidate products are taken on to reservoir condition coreflooding. In the screening of topside scale inhibitors, no adsorption tests are conducted.
Results from adsorption and precipitation type corefloods will be compared for polymer and phosphonate chemistries selected using these screening procedures. Such corefloods serve both to evaluate the squeeze lifetime performance and to assess the levels of formation damage caused by the scale inhibitor package. The strategy of deriving a dynamic isotherm which can be utilised in computer modelling of the coreflood data to produce a "Field Squeeze Strategy" will be outlined. This systematic approach provides a set of effective and economical methods for the chemical screening of scale inhibitors. This results in an improved field application strategy with longer squeeze lifetimes, while minimising formation damage potential.
The downhole and topside formation of both sulphate and carbonate inorganic scales can be a serious problem in oilfield production operations. One of the most common and efficient methods for preventing the formation of such deposits is through the use of chemical scale inhibitor "squeeze" treatments. Two main types of inhibitor squeeze treatment can be carried out where the intention is either (a) to adsorb the inhibitor on the rock substrate by a physical-chemical process using a phosphonate or a polymeric material; or (b) to extend the squeeze lifetime of poorly adsorbing scale inhibitors by precipitation (or phase separation) which is commonly achieved by adjusting the solution chemistry ([Ca2+], pH, temperature) of a polymeric inhibitor such as poly phosphino carboxylic acid (PPCA).
The central factor governing the dynamics of the inhibitor return curve in adsorption/desorption treatments is the inhibitor/rock interaction as described by the adsorption isotherm, (C). This is a function of the inhibitor type, molecular weight, pH, temperature, mineral substrate and the brine strength and composition. The precise form of (C) determines the squeeze lifetime, as has been described in detail in a number of previous papers. The "precipitation squeeze" process is based on the formation of a gel-like calcium salt, usually of poly phosphinocarboxylic acid scale inhibitor, within the formation. "Precipitation" (or phase separation) is controlled either by temperature and/or pH although it will generally involve a coupled adsorption process.
In this paper, our objective is to present a general methodology for the screening of chemical scale inhibitors for both downhole and topside applications. This is illustrated by results generated for application in four North Sea fields, although the Oilfield Scale Research Group have actually applied these methods to over 20 fields.
Data collected during gravel packed completions may be analyzed to evaluate the impact of specific completion practices on well performance. Operations where gathering data is critical are: (1) during the initial flow and perforation cleanup after underbalanced perforating, (2) during prescribed injection tests prior to gravel packing, (3) during periods in which fluid is being injected into the formation (pre-packing perforations, fluid loss after perforating, fluid loss after gravel packing), and (4) during stabilized flow after the well is brought on line. This data can be used to calculate an approximate value for kh (md.ft.) and an instantaneous completion efficiency at different stages of the completion. By comparing these instantaneous completion efficiencies, the damage contribution of certain operations and the damage prevention aspects of other operations may be quantified. This methodology should provide a valuable resource to those pursuing continuous improvement in well completion operations, particularly those involved in sand control.
Laboratory studies and field case histories are presented that demonstrate enhanced well productivity when selection and formulation of solids-free, high density completion fluids are optimized prior to field use. Results of return permeability studies and compatibility tests between completion fluids and formation fluids are presented. These results illustrate the tendency for high density completion fluids to form stable emulsions with certain crude oils. Studies supporting the treatment of these fluids with non-emulsifiers, surface tension reducing surfactants or mutual solvents to reduce formation damage are discussed. Preliminary data describing unique chemistry of calcium chloride, calcium bromide and zinc bromide solutions are provided. These properties influence recovery of high density fluids from oil or gas formations.
The chloride and bromide salts of calcium and zinc are highly soluble in water. In combination, solutions of up to 19.2 pounds per gallon (ppg) density can be obtained. These solids-free solutions, commonly referred to as high density (HD) brines, are widely utilized in completion and work-over operations. The ability to achieve hydrostatic well control without solids has made HD brines the work horse of the completion industry. As pure solutions, HD fluids are inherently stable and relatively compatible with both well operations and petroleum bearing formations. Nonetheless, HD brines are most economically utilized when completion and work-over operations are engineered to minimize fluid losses to the productive interval. Reduced fluid costs and enhanced well productivity are the result.
One objective of this paper was to provide experimental data not previously published and that may impact the interaction of HD fluids with formation matrix. Load water recovery, fluid-fluid compatibility and shale/clay stability are areas of particular interest. Data presented in this paper include: (l) activity of water for various HD solutions, (2) viscosity of brines as a function of composition and temperature, (3) surface tension of typical HD brines, and (4) capillary suction time (CST) after exposure to clay minerals. Core flow studies using field and Berea cores were conducted to evaluate recovery of reference fluid (formation water, oil or gas) after saturation with HD completion fluid. In all core flow studies, fluid permeability was calculated. Several tests included ion analysis of the core effluents by inductively coupled plasma emission spectroscopy (ICP).
The formation damage caused by the injection of water containing suspended particles, which are stable and are not adsorbed spontaneously onto pore surfaces under Brownian motion, has recently been analyzed at a pore scale level. Formation damage is the result of four more or less overlapping successive steps: (1) deposition on a grain surface, (2) formation of mono- or multiparticle bridges with subsequent accumulation upstream from the bridges, (3) internal cake formation as soon as the nonpercolation threshold has been reached near the core entrance, and (4) external cake formation. The surface deposition is not uniform over the grain surface and varies from the upstream stagnation point to the near pore throat zone according to a function depending on flow rate and surface forces. The bridging of pore throats is strongly dependent on the effective pore throat-to-particle size ratio, and the pore-throat size is often reduced by previous surface deposition.
A new model has been developed to predict formation damage while taking into account these different steps. The dominant mechanism in each step is governed by parameters that have a clear physical meaning. However, due to the complexity of natural systems, these parameters cannot be quantitatively predicted from theoretical considerations but can easily be determined by specifically designed lab experiments. The model predicts the retention by deposition, by bridging and by subsequent accumulation upstream from bridges, the concentration in flowing particles and the local permeability reduction as a function of the distance from the inlet, as well as the overall permeability reduction, and the beginning of external cake formation.
This new model appears to be an effective tool for analyzing the consistency of a set of laboratory data and for selecting the values of the parameters that must be introduced in a near-well bore field simulator for the proper prediction of formation damage in a given application.
The early models proposed in the oil literature aimed to fit the decrease in relative permeability observed when a particle suspension is injected into a permeable core. Thus these models are empirical or at best purely phenomenological in the sense that they simulate observed phenomena by using equations without any clear physical meaning. They are very attractive however for petroleum engineers since they are very simple and easily introduced in conventional field simulators without increasing computing time too much. A good review of these empirical models can be found in Ref. 1.
To maximize well productivity, it is essential to maximize fracture cleanup. A field study in the Codell formation of Colorado was conducted to examine the effects of guar removal from hydraulic fractures on gas production.
The conventional method of quantifying cleanup from a hydraulic fracture has been to report load water recovery; however, this value is affected by any formation water that might be produced. A more quantifiable approach to describing fracture cleanup has been performed in this study by determining the amount of guar returned from the fracture during flowback A 12-well study was performed by sampling flowback fluids during cleanup. The concentration of guar in each sample was determined using a colorimetric technique allowing the total amount of polymer recovered over the flowback period to be calculated.
Under equivalent reservoir conditions (pressure, permeability, etc.) and fracture conditions (width, proppant loading and distribution, etc.), physically, it is reasonable to expect higher production rates from wells which have produced back more guar since a larger volume (porosity) will be available for flow. Under low permeability reservoir conditions such as those in the Codell ( 0.01 md), this guar removal will need to provide added length to show an increase in production. This concept is illustrated with field data. For example, wells whose fractures produced 600-700 lb of guar ( 180,000 Ib proppant) produced gas at rates of 35-40 MSCF/D whereas wells whose fractures produced 1100-1200 lb of guar produced gas at rates of 70-80 MSCF/D, most likely indicating a cleanup over a longer length of the fracture.
In addition, the effects of flowback rate on load water recovery, guar concentration, and guar recovered are illustrated.
INTRODUCTION AND BACKGROUND
Attempts to understand the effects of load recovery on well productivity have been made over the years. In 1975, Claude Cooke wrote that "residue from guar polymer is the most important material presently used in fracturing fluids that can cause fracture conductivity reduction!" In the years since this comment, little has been done to address the effects of polymer. Recently, the development of new breaker technology and its successful field application has led to renewed interest in the area of polymer load, polymer type, residue and fines recovery.
Fluid cleanup or load recovery can impact well productivity dramatically. A number of parameters have been shown to play an important role in fracture fluid cleanup or load recovery. The most important of these include relative permeability, fluid viscosity, proppant fines, and gel residue. The most common effect deals with the reduction in the formation relative permeability to the hydrocarbon phase by the injection of a water based fracturing fluid.
In reservoirs where relative permeability impairs well performance, alternatives to conventional water based fracturing fluids such as carbon dioxide and/or nitrogen foams (minimal water component), and hydrocarbon based fluid systems are considered to reduce or eliminate the production impairment during well cleanup.
Fracture fluid viscosity also plays an important role in well performance during fracturing cleanup! It has been shown that viscosities in excess of 50 cp seriously impair well performance. Breakers are utilized in our fracturing fluid systems to reduce viscosity following fracture treatments to aid fracture fluid cleanup. Breaker technology has made significant advances in recent years. We should ensure that we utilize these technological advances to optimize our well performance.
In addition to the effect of relative permeability and fracture fluid viscosity on well performance, the other performance impairment comes from material left in the proppant pack itself. This material can significantly affect well performance throughout the life of the well. Materials of concern to the pack include both formation and proppant fines as well as gel residue. Reduced proppant pack permeability means detrimentally affected well performance. The effect of formation and proppant fines on porosity reduction can be conceptualized readily; the effect or significance of polymer residue is much more difficult to appreciate, although equally devastating to well performance.
Estimation of completion pressure losses in gravelpacked and frac-packed wells is generally performed through use of empirical or semi-empirical analytical relations. This paper reports on work conducted by Conoco to compare numerical simulation results with analytical inflow performance relations. The work shows how and where completion pressure losses occur in flow to gravelpacked and frac-packed wells.
A fine gridded finite difference model has been developed to simulate flow and pressure loss behavior in the reservoir/well system. The grid system employs elements as small as 1 cm3 to model complex near well and intra-well flow effects including near-wellbore flow convergence to perforations, flow distribution between perforations and flow through gravel-filled perforations. Those near-wellbore effects are reviewed for both symmetrical gravelpacked well flow cases and asymmetrical flow cases associated with frac-packed wells. Intra-well flow through gravel-filled perforation tunnels and the casing/screen annulus is also modelled for both cases.
Pressure losses and skin effects due to damage, fracturing and wellbore geometry are calculated through the flow system and compared to predictions from analytical relations. Results of these comparisons lead to an improved understanding of the effects of damage and flow asymmetry on gravelpacked and frac-packed well performance. Further, they show how current analytical skin relations can be enhanced to provide more effective completion pressure loss predictions.
Frac-packing is a relatively new completion technique in which a small fracturing treatment is combined with a cased hole gravelpack. The fracture is designed to increase well flow capacity, providing a highly conductive path to the well that effectively bypasses near-wellbore damage and minimizes radial convergence effects. The perforations, perforation tunnels and annulus between the gravelpack screen and the casing are then packed with sized gravel to prevent formation sand from entering the wellbore.
This paper discusses a numerical simulation study of frac-packed completions conducted by Conoco's BDR-Technology Group. Study results provide insight into how frac-packed wells achieve high productivities and shows areas where they are most susceptible to damage. The paper breaks the study into three parts, corresponding to the major phases involved in the work.
Effective diversion is critical to successful stimulation of long-interval, high-rate wells. Once near-wellbore damage has been removed in one portion of the completion interval, steps must be taken to divert stimulation fluids to intervals that remain damaged. Viscous fluid diverters, such as gels, foams, and emulsions, have all been used with success in field applications. These three diverter types were compared in the Westport Technology Center wellbore model. Foams and emulsions were found to provide more effective diversion than gel.
Based on the laboratory results, foam diversion was used during stimulation of injection wells at Shell Offshore Inc.'s Bullwinkle platform. Comparison of diverted and undiverted treatments quantifies the benefits to be gained from effective diversion and demonstrates that wellbore model studies correlate well with field results.
In many cases, the purpose of well stimulation is removal of near-wellbore impairment to increase well performance. Plugging of perforations, the near-wellbore formation, or sand control installations such as screens or gravel packs may all contribute to high pressure drop (skin) during production or injection. A variety of materials commonly deposited during completion, production, or injection can contribute to near-wellbore impairment. Although most of these materials are soluble in the appropriate solvent, removal is difficult in practice because of inadequate contact between the solvent and the deposit to be dissolved.
In fact, effective action of the solvent may make it more difficult to dissolve the bulk of the target damage. Once damage is removed from a portion of the wellbore, the solvent naturally flows into that portion and cleaning action on the rest of the wellbore is lost. While in principle these considerations apply to any damage/solvent couple, they apply commonly to matrix acidizing in sandstone reservoirs, the subject of this paper.
The simplest way to ensure adequate injection of acid into the damaged portion is to increase the injection rate so that the bottomhole pressure remains high.1,2 There are practical difficulties with this approach. For example, friction pressure drops may cause wellhead pressure to exceed safe limits, or available pumps may not be able to maintain required rates and wellhead pressures. The volume of acid required may exceed available capacity or budget. Injection of large volumes of acid into the undamaged (or rapidly cleaned) zones that receive the bulk of injection may not be acceptable for other reasons such as reduction of formation strength.
Diverting agents have been widely applied, both particulates that work by temporarily forming a low permeability filter cake and fluids that work by increasing flow resistance (apparent viscosity).2,3,4 Particulates have limited application to treating gravel packs where flow behind the screen may redistribute acid in an undesired manner. Diverters that increase flow resistance of injected fluid provide yet another strategy for improving the distribution of fluids during stimulation. Examples are polymers, foams, and emulsions which increase viscosity and provide shear thinning characteristics.
The fluids commonly used in frac-pack treatments were initially designed for either fracturing low permeability formations or for conventional gravel pack operations. These fluids do not address the unique problems found when fracturing higher permeability formations. Conventional fracpack fluids (borate crosslinked guars and HEC) undergo whole polymer leakoff, and create a deep invasion bank of concentrated polymer that is very difficult to break and can lead to high formation damage.
Viscoelastic surfactant (VES) fracturing fluids have been developed which exhibit excellent rheological properties and still maintain low formation damage characteristics even in high permeability formations. These fluids are completely polymer free and do not rely on internal chemical breakers to degrade the fluid viscosity.
This paper will detail the results of recent laboratory studies on viscoelasitic surfactant fracturing fluids, and will compare the rheological and formation damage properties to other conventional fracturing fluids. The laboratory findings will be substantiated by several field case studies.
For many years fatty amine quaternary ammonium salts have been used as thickeners for consumer products (e.g., bleach, liquid dishwasher detergent). Such materials, called viscoelastic surfactants , are a class of compounds that form micelles in an aqueous system containing certain cations, and impart viscoelastic properties to the liquid. The deformation of such systems is time dependent (i.e., the system acts as a solid unless a sufficient amount of shear has been applied for a certain length of time). When the system deforms, the rheological behavior is nearly Newtonian (Fig. 1).
The texture of such fluids at rest is similar to that of gelatin: therefore, they are excellent particle-suspension media, and have been used for several years in gravel packing applications.1 The surfactant is added to common completion brines, and the resulting fluid effectively suspends sand/proppant. The concentration of surfactant required to provide adequate suspension varies from 2.5% to 6% (by volume), depending on the anticipated fluid temperature. VES fluids are very easy to prepare in the field. A simple dilution of the concentrate in brine, with minimal agitation, is all that is required.
Viscoelastic (VES) fluids have more recently found application as a fracturing fluid for high permeability formations. 2 As shown in Fig. 2, the leakoff behavior of VES fluids is less dependent upon differential pressure than HEC fluids. At fracturing pressures, the fluid-loss rates of VES fluids are lower than those observed with HEC fluids. At production rates, VES fluids should be more mobile than HEC fluids.
The viscosity of VES fluids can be broken via two mechanisms: (1) contact with oil or condensate: and (2) reduction of the salt concentration. Since one or both scenarios occur during cleanup in any well, no additional breaker chemicals are required. The principal advantage of a VES fluid is that, unlike polymer-based systems such as HEC or guar, very little residue is left upon breaking. As a result, less formation damage is observed. Typical VES fluid performance is illustrated in this paper, including rheology, fluid-loss and core-cleanup data.
This paper describes the successful application of the frac-and-packcompletion technique to a low-permeability oil-bearing formation in coastalZaire, West Africa. Using various completion methods since initial fielddevelopment in the early 1970s, operators have recovered less than 1% of theestimated oil in place from this formation to-date. Encouraging results from atwo-well pilot project initiated in late 1994, led to a decision to work overan additional four wells for frac-and-pack completions in 1995 as part of thepilot project.
This work centers around the Turonian formation, which is a soft,low-permeability siltstone formation. The friable nature of this formationcombined with a low median sand-grain size (20 to 40 microns) has led toformation sand and fines production in some wells. Past attempts to stimulatethe Turonian through matrix acidizing have been unsuccessful, and completionsof the reservoir with both open- and cased-hole gravel packs have shownuneconomical production rates.
The first two frac-and-pack treatments of the pilot project, one in casedhole and one in a 15-in. underreamed open hole, were pumped through a shortweight-down gravel pack assembly that allows for monitoring a live annulusduring the job and accurate measurement of net fracturing pressures. The fouradditional frac-and-pack completions were performed with a similar downholeassembly.
This paper highlights the main aspects of this project, including thereservoir description, completion equipment, fluid and proppant selection,design and analyses of the fracture treatments, and optimization of thetreatments as the project progressed. A summary of well performance followingthe frac-and-pack completions is also presented.
The Liawenda field is located onshore Zaire in the Congo basin of centralAfrica. This basin extends southward from Zaire into northern Angola andnorthward through Cabinda into the Congo Republic. Oil accumulations have beenfound throughout the basin in several formations.
Conventional matrix acidizing treatments rely on hydrochloric acid to stimulate carbonate formations. However, the success of these treatments is often limited because of rapid acid spending at low injection rates and asphaltic sludge precipitation. This study investigated ethylenediaminetetraacetic acid (EDTA) as an alternative stimulation fluid. Results show that EDTA can effectively wormhole in limestone, even when injected at moderate or non-acidic pH values (4 to 13) and at low flow rates where only face dissolution would occur with HCl. Stimulation with EDTA at low injection rates is consistent with the dependence of the wormhole structure on the Damkohler number for flow and reaction. Sludge tests show that EDTA does not induce the precipitation of asphaltic sludge from crude oil, even in the presence of 3000 ppm of ferric iron. This result is attributed to EDTA being able to form stable chelates with ferric and ferrous iron.