Summary A new computer-controlled laboratory technique has been developed to measure propped fracture width and embedment in weakly consolidated cores or unconsolidated sands under simulated down-hole conditions. Previously, laboratory studies on cores had determined embedment in hard rocks where embedment was normally limited to 50% of the proppant grain diameter. Several studies also indicated the importance of embedment with one monolayer or less of proppant coverage. The effects of water saturation and fracture-fluid filtrate on formation softness and embedment have not been previously published. Consequently, the objectives of the current paper are to extend previous research results to include soft, weakly consolidated cores and unconsolidated sands with multiple proppant layers. The influence of water saturation and dynamic fluid leakoff on embedment are also shown to be important. The current investigations indicate that embedment becomes a problem when the Brinell hardness (BH) of the formation is less than about 20 kg/mm2 or when the static Young's modulus of formations cores is less than about 2 million psi (13 GPa). Embedment has been determined for cores with static Young's moduli between 0.1 and 1.4 million psi (0.7 to 9.6 GPa). In soft and wet sandstone, embedment can reduce fracture width up to 60% or more for proppant concentrations of 2 lbm/ft2. For unconsolidated sands, embedment is influenced by fracturing-fluid type, water saturation, and downhole conditions. Cyclic loading conditions associated with well shut-ins also increase embedment in unconsolidated sands. This paper reviews and discusses test data on formation cores from south Texas, New Mexico, the North Sea, and the Gulf of Mexico. Most of the commercial fracture-design programs neglect embedment problems in calculating fracture width, while other fracture simulators contain allowances for embedment. Introduction Proppant embedment is a more significant problem today than in the past because of fracturing-stimulation treatments in weakly consolidated formations. Unlike previously published investigations on hard rocks, embedment can be as high as several proppant-grain diameters in some weakly consolidated sandstones. Proppant embedment can reduce fracture width from 10 to 60% with subsequent reduction of productivity from oil and gas wells in weakly consolidated sandstone. Simple estimations with a parallel-plate model indicates that fluid flow to the well will be reduced proportionally to the cube of the fracture width. Consequently, a 20% reduction in fracture width might restrict fluid flow and recovery by 50 to 60%. To evaluate embedment in soft rocks and unconsolidated sands, a new computer-controlled apparatus was designed to determine propped fracture width and embedment as a function of closure stress. The effects of fluid type and variable proppant densities were also investigated. The dynamics of fluid flow and proppant settling can be evaluated as the fracture face meets the suspended proppant grains that support the closure stress. This paper also reviews the effects of cyclic loading conditions caused by simulating production and well shut-ins. Yarbrough, McGlothlin, and Muirhead1 studied the effects of proppant embedment for the Lost Hills field, California. Embedment was considered to be a problem for low-formation-hardness values and proppant coverage less than 0.75 monolayers. Volk et al.2 studied embedment of sintered bauxite into Berea sandstone and shale with closure stresses up to 10,000 psi using one monolayer. The percent of fracture closure depended on the roughness of the fracture face and proppant diameter. Much and Penny3 reported on a study of fracture conductivity using an API proppant conductivity cell with Ohio sandstone and several proppants for closure stresses of 5,000 and 8,000 psi. Some of the proppant conductivity loss was associated with embedment of 0.008 in. (0.32-grain diameters) and crushing of sand. They also demonstrated that the filter-cake buildup can reduce fracture conductivity by 50%. Snow and Hough4 determined embedment in chalk formations in the North Sea with BH values between 10 and 35 kg/mm2. In a more recent laboratory study, Milton-Taylor et al.5 determined that proppant pack stability in flowback tests depended on proppant size and rock hardness. Martins, Leung, and Jackson6 indicated lost fracture width caused by embedment for proppant concentrations between 0.5 to 1 lbm/ft2. Harley and Bosma7 reviewed embedment problems studied in a non-API conductivity cell with rock-hardness values between 50 and 1,000 MPa (5 and 100 kg/mm2) in a chalk reservoir. Recently, Park8 measured embedment of 20/40 quartz gravel for confining stress of 1,000 psi in unconsolidated sands. Park noted the lack of embedment at high-flow-rate conditions and at low confining stress for nonspherical gravel. Additional papers6–12 have discussed the importance of embedment on field performance. The current work has recently (in 1997) been extended to include unconsolidated sands,12 where the formation hardness is only 0.1 kg/mm2 (140 psi), and different fluids and proppant sizes are investigated. Currently, some fracture designs ignore embedment in calculating the propped fracture width, while others contain allowances for embedment at 2 lbm/ft2. If commercial software programs for fracture designs assume no embedment, this corresponds to assuming that all rock formations have the hardness of steel. Formation-rock-hardness values, as measured on a ball penetrometer (i.e., BH), can vary from about 0 to about 400 kg/mm2 (5.69×105 psi) . The formation-hardness value is a more important factor today because of recent industry trends to fracture softer, weakly consolidated, and higher-porosity formations where BH values are generally less than about 20 kg/mm2 (28,400 psi). The current laboratory tests were performed on unconsolidated sands and soft, weakly consolidated sandstone with static Young's modulus values between 0.1 and 1.4 million psi, closure stresses up to 10,000 psi (70 MPa), and proppant concentrations of 2 to 4 lbm/ft2. Both dry and water-saturated cores were evaluated. The following two sections describe the testing technique and formation properties. Test data on cores from south Texas, the Gulf of Mexico (GOM), the North Sea, and New Mexico are reviewed in the section on laboratory test cases.

Tiws paper was selected for presentation by an SPE Program Committee follov+ng review of ttiormation contained in an abstract submitted by the author(s) Ccmtenk of the paper, as presented, have not been reviewed by the Sociew of Petroleum Engineers and are subject to correction by the atihor(s). The material, as presented, does not necessarily reflect any position d the society of Petroleum Engineers, its offcers or membm Papers presented at SPE meetings are subject to pubrrcation revkw by Editorial Committes of Me Scciety d Petroleum Engineers Electronic reproduction, distribution, or storage of any part d thk paper for mmwrwrcial purposes without the written consent of the !%mty of Petroleum Engineers is prohibited %rni+on to reproduce in print is restricted to an atstracf cf not more than 390 words, illustrations may not be copied Tne abstract must contain conspicuous ackno.%ledgment of where and by whcm the @per was presented Write Llbranan, SPE. P O sax E!33KX3. Richardson. TX75083-3836, U SA.. fax 01-972-952-9435 ABSTRACTStress cycling of proppant packs often occurs during well production opemtions and is known to be a major contributing factor to proppant pack failure. Proppant crushing occurs due to increasing closure stress as a well is drawn down. The fines generated by such crushing can cause significant damage to proppant pack porosity and fracture conductivity. Additionally, the incidence of proppant flowback (fines and whole proppant) has ken reported to be exacerbated by stress cycling.The addition of deformable Ixads to the proppant pack has been observed to alLeviate both problems and may signflcantly improve well performance. Testing of various mixtures of the deformable beads and proppant has demonstrated significant reductions in the amount of fines generated and accompanying improvements in proppant pack permeability.Furthermore, the initiation of proppant flowback was observed to require much higher flow rates than in the absence of the beads.It is thought the process of bead deformation serves to "cushion" the proppant particles from the Ml brunt of the stress. New laboratory facilities and procedures have been established to study and quanti@ proppant flowbac~and conductivity as a fimction of proppant. temperature. flow rate. fracture widfi closure stress, and cycle frequency.

In deviated wellbores, the relationship between friction pressure and hydrostatic pressure differs from that in vertical wellbores. The change in this relationship increases the need for accurate slurry friction pressure modeling. Because of deviation, incremental slurry friction pressure changes are more significant than incremental changes in hydrostatic pressures. Real-time calculation of an accurate bottomhole treating pressure in deviated wellbores is more difficult to achieve, than in vertical wells, because of the lack of accurate slurry friction models. 'Abnormal' surface treating pressures, which are caused by this change in relationship, were recorded while fracturing deviated wells in the Prudhoe Bay Field in Alaska. The significance of this relationship is presented along with observed slurry friction pressure data obtained through the use of bottomhole pressure recorders. A methodology and mathematical model for more accurate calculation of slurry friction pressure is presented for these conditions. Introduction While performing fracturing treatments in vertical wells with the tubular and treatment conditions presented here, the surface treating pressure will normally decrease when proppant is added and proppant concentrations increase. 'Abnormal' or increasing surface treating pressures have been recorded while fracturing highly deviated wells. Misinterpretation of these surface pressure increases can cause erroneous decisions to be made during the fracturing treatment. Figure 1 is a hypothetical plot of surface treating pressure, slurry rate, and proppant concentration versus time for a frac job performed in a near vertical well. This example shows a continual decrease in surface treating pressure with proppant addition. Figure 2 is a hypothetical plot of the same parameters on a well that has a high angle of deviation from vertical. Note that at first, the surface treating pressure decreases when proppant is added but then begins to increase as the proppant concentration increases. The hydrostatic and tubular friction pressures must be accurately calculated during the treatment in order to obtain the net bottomhole treating pressure for proper analysis. Hydrostatic pressures are fairly simple to derive if the slurry density is monitored at the surface. The tubular friction pressure must be calculated based on a friction pressure model that is incorporated into the real-time computer monitoring package. This parameter is much more difficult to predict because of the variables involved. Because of the higher significance of friction pressure in highly deviated wells, proper slurry friction pressure modeling is even more critical. To properly understand this pressure phenomena and its significance, one must first have a thorough understanding of surface treating pressure and its components. FRACTURING PRESSURES The fracturing surface treating pressure is a function of four basic pressure components: hydrostatic head, pipe friction pressure, perforation friction pressure, and the formation fracturing pressure or bottomhole treating pressure. Their relationship is expressed in the following equation: (1) P. 771^

This paper was saktad for presentation by an SPE Prcgram Comnittee fdlming review of information mntainsd in an abstract submitkd by the author(s) Contents cf the paper, as pr=ented, have nd ken reviawad by the Sccis4y of Patrdeum Enginaars and are subjed to cwsction ty the author(s), The matsrial, as pras.entad, does not nacsssarily rafkt any pcsition of the SOdety c4 Petmlwm Engineers, & Mic.ers, or memtws. Papers presented al SW matings are subjsd to pubkation review by Ecfrrorial Comrrilks of the Society of Petroleum Engineers. Ektmnic reproduction, dstributicm or storage of any part of Ibis paper for commwcisl purposes without the wittan wrtsamt of ths SC&@ c+ Petroleum Enginaera is prohibited. Petission to rOpfOduGS in PM is resbictad to an abstract d not more than SOfJWNIS illuslmtions may not ba copied, The abstract must contain conspdcuotis A?m'Aedgment of where and by whom the papar wds prasentad. Wr'ikI Librsnian, SPE, PO. Box KBX?43, Rchards.m, TX TS08XWB, U. S. A., fax 01-972-952-9485. AbstractA new water-soluble perforation ball sealer has been developed and successfully used as a substitute for conventional ball sealers. They also can and have been used in situations where conventional ball sealers would not be an option due to the potential of creating undesired costly workover operations.The introduction of a degradable or water-soluble ball sealer signifies a major breakthrough in ball sealer technology. This paper discusses the new ball sealer chemical and physical properties and development methodology. Laboratory testing teehniqnes and methods are presented. This paper foeuses on the labomto~testing conducted during the development phase and the data genemted to support proper application in the field. Also, the potential benefits of watersoluble ball sealers are presented along with examples of successfid application in wells.

Acidizing high-temperature wells has always been a challenge due to problems associated with corrosion of tubulars and loss of acid carbonate dissolving efficiency. Typical acid treatments of offshore wells with extreme downhole temperatures are carried out using retarded acids, which often degrade, form insoluble salts, and require further neutralization of flowed back spent acid, resulting in loss of production days. Recently there has been a growing interest in using amino-polycarboxylic acids such as glutamic acid, N, N'-diacetic acid to treat carbonate or sandstone formations with high bottomhole temperatures. The benefits of using such acid for high-temperature acidizing are lowered reactivity, inherent chelation chemistry, better tubular protection and biodegradability.Extensive laboratory testing was conducted before a field trial of the acid. A corrosion test conducted at 395°F using highly corrosion-resistant coupons (identical to the metallurgy of the tubular) without corrosion inhibitor had a corrosion rate of 0.0068 and 0.0069 lb/ft 2 , respectively; thus, corrosion inhibitor may or may not be included in the acid used for field treatment. About 2.38 pore volumes of the acid broke through a carbonate core, dissolving 452 mg of calcium at 300°F. A computed tomography scan of the treated core showed a highly branched wormhole distribution network. The acid was found to be compatible with brines and different elastomers often used in downhole completions.The successful removal of wellbore scale and formation damage in a couple of offshore wells with high bottomhole temperatures with an amino-polycarboxylic acid is presented.Detailed laboratory testing that supported the treatment design and field application will be reported. Production enhancement as a result of the treatments, challenges with the treatment process will also be presented.