Optimal Fluid Systems for Perforating

Transcription

1 Optimal Fluid Systems for Perforating Recent developments in perforating fluids are helping operators clean up, both literally and financially. When combined with advances in perforation-gun performance and dynamic underbalanced-perforating technology, these new fluids yield significant improvements in well productivity. Larry Behrmann Ian C. Walton Rosharon, Texas, USA Frank F. Chang Dhahran, Saudi Arabia Alfredo Fayard Houston, Texas Chee Kin Khong Shekou, Shenzhen City, China Bjørn Langseth Stavanger, Norway Stephen Mason Sugar Land, Texas Anne-Mette Mathisen Hydro Bergen, Norway Italo Pizzolante Tian Xiang CACT Operations Group Shekou, Shenzhen City Grete Svanes MI-SWACO Bergen, Norway For help in preparation of this article, thanks to Nils Kågeson-Loe, MI-SWACO, Stavanger; and Charlie Svoboda, MI-SWACO, Houston. PLT (Production Logging Tool), PURE and SPAN (Schlumberger perforating analysis) are marks of Schlumberger. CLEANPERF is a mark of MI-SWACO. Cleaning up after any well operation is critical. In drilling, rock is loosened by the impact of a drill bit and the hydraulic energy of a drilling fluid. Drilling mud carries this rock debris to the surface. Even before the circulating mud removes the loose drilling debris, the formation has been exposed to foreign solids, liquids and chemicals in solution that sometimes damage reservoir rock by reducing near-wellbore permeability. This reduction is often referred to as formation damage, one of the components of skin damage. Similarly, in perforating, a high-energy jet from an explosive shaped charge shoots through casing and cement, and pierces the formation, creating a conductive path deep into the reservoir rock. Immediately after gun detonation, fluid from the borehole fills the perforation tunnel. As in drilling, this initial contact between the wellbore fluid and formation may cause an additional reduction in permeability and a decrease in perforation efficiency. This is particularly true in over - balanced perforating, a condition in which wellbore hydrostatic pressure is greater than formation pressure. A properly designed perfor - ating fluid can help avoid this damage and substantially improve well productivity. Although many technologies are involved in modern perforating, three fundamental elements are critical to maximizing hydrocarbon recovery. Together, they form the basis for an optimized perforation strategy. First, perforations must be properly oriented; second, debris from the perforation tunnels must be effectively removed; and third, formation damage must be minimized during the process. Debris includes not only loose material in the perforation tunnel, but more importantly, crushed sand grains that line the tunnel and constitute what is known as perforation damage. In reservoirs with a potential for sand production, perforation orientation is critical to sustained production. This is particularly true in deviated and horizontal boreholes. Excessive sand production is a common problem that erodes downhole equipment, plugs the wellbore and ultimately chokes off fluid flow. In 21, BP noted that 6% of its worldwide production, or around 2 million barrels [317,8 m 3 ] of oil equivalent per day, came from fields requiring some level of sand management. 1 Numbers like this reinforce the need for an optimized perforating strategy to ensure that perforations are placed at the proper orientation and phasing to minimize sand flow and maximize hydrocarbon production. 2 After perforating, tunnel debris must be removed. Long perforation tunnels and those in hard, low-permeability formations can be difficult to clean. Underbalanced perforating is sometimes used to help clear these tunnels of debris and minimize perforation damage. 3 However, more recently, engineers have recognized that generating a dynamic underbalance just moments 14 Oilfield Review

2 after perforating-gun detonation may actually promote better perforation cleanup than under - balanced perforating, and in some cases, is better suited to the completion design and well conditions. 4 A dynamic underbalance can generally be created from an initial state that is either under- or overbalanced. 1. Morton N: Screening Out Sand, BP Frontiers, issue 2 (December 21): For more on perforation orientation: Bersås K, Stenhaug M, Doornbosch F, Langseth B, Fimreite H and Parrott B: Perforations on Target, Oilfield Review 16, no. 1 (Spring 24): Acock A, ORourke T, Shirmboh D, Alexander J, Andersen G, Kaneko T, Venkitaraman A, López-de- Cárdenas J, Nishi M, Numasawa M, Yoshioka K, Roy A, Wilson A and Twynam A: Practical Approaches to Sand Management, Oilfield Review 16, no. 1 (Spring 24): For more on underbalanced perforating: Bakker E, Veeken K, Behrmann L, Milton P, Stirton G, Salsman A, Walton I, Stutz L and Underdown D: The New Dynamics of Underbalanced Perforating, Oilfield Review 15, no. 4 (Winter 23/24): Chang FF, Kågeson-Loe NM, Walton IC, Mathisen AM and Svanes GS: Perforating in Overbalance Is It Really Sinful?, paper SPE 8223, SPE Drilling & Completion 19, no. 3 (September 24): Spring 27 15

3 Overbalance, psi Underbalance, psi 2,5 2, 1,5 1, 5 5 1, 1,5 2, 2, Time, s > PURE pressure dynamics. Within.1 s of perforating gun detonation, pressure (blue) in and around the perforation decreases dramatically. In a wellbore open to the surface, pressure recovers to that of the hydrostatic load at around.15 s. This action helps clear the perforation of shattered formation debris and improves production efficiency. To minimize perforation damage as hydrostatic pressure recovers, the perforating fluid must quickly generate a competent filtercake, or seal, over the newly exposed formation. Undamaged formation Low-permeability zone and perforation debris expelled by surge of formation fluid Internal filtercake Liquidinvasion zone External filtercake Filtration surface Cement Casing Formation damage from drilling > Filtration at the formation face. In an overbalanced condition, when the wellbore hydrostatic pressure is greater than formation pressure, the formation face within the perforation acts as a filter. As the fluid in the wellbore is pushed into the formation by the pressure differential, solids are filtered out at the rock face leaving only the liquid and fine particulates to migrate back into the permeable rock (inset). The size of the particles allowed past the initial filtration zone is, for the most part, a function of the rock s pore-throat size and the dimensions and characteristics of the solid-phase materials contained within the fluid. Typically, solid materials are deposited just inside the formation and across the surface forming an internal and external filtercake. The depth, thickness, elasticity and other mechanical characteristics of the cake determine its ease of removal during production. Perforation tunnel The PURE perforating system for clean perforations generates a dynamic, or transient, underbalance pressure immediately after the creation of the perforation tunnel. 5 This instantaneous decompression of reservoir fluids around a perforation assists in removal of the crushed material from the perforation tunnel while the rest of the well may be in a static overbalanced condition (left). In most cases, the PURE technique produces a lower skin than that observed after conventional underbalanced perforating. Once the guns have detonated at the required orientation and a dynamic underbalance has helped clean the perforation tunnels, the hydrostatic pressure in the perforations returns to that of the wellbore. If the initial wellbore state is underbalanced, then there is little opportunity for wellbore fluids to infiltrate the formation through the perforation tunnel. However, depending on the well configuration and formation characteristics, when perforating overbalanced, fluid from the wellbore may rush to fill the perforation tunnels, providing an increased potential for further damage to the formation. Engineers recognize that perforating with an initial overbalance is potentially damaging and sometimes unavoidable. However, overbalanced perforating is often the most economical and efficient process, particularly when the operator needs to remove the gun assembly from the wellbore after perforating. The operator essentially has three options: Drop the guns immediately after perforating. This requires a special connector called a drop sub, sufficient wellbore depth below the completion, a wellbore deviation less than about 6 degrees and prior installation of the upper completion. In these circumstances, the well can be perforated with an initial underbalance, the guns dropped and the well immediately placed on production. This is the least damaging of the three choices. Perforate with an initial underbalance and then retrieve the guns through a wellhead adapter that allows tools to be pulled through the wellhead while under pressure. This method causes little damage to the formation, but the use of these specialized tools is not always a practical or cost-effective option. Perforate overbalanced so that the guns can be safely retrieved and the upper completion installed with the well under control. In this case, the perforating fluid, often a solids-laden kill pill, is generally circulated out of the wellbore before the well is placed on production. 16 Oilfield Review

4 In this article, we focus on the third element of an optimized perforating strategy, the perfora - ting fluid. We describe extensive laboratory tests that form the foundation for development of a new perforating-fluid system. Then, we show how one operator in the South China Sea utilized these theoretical concepts to improve production efficiency. Evaluating Fluids for Overbalanced Perforating As fluid leaks off into a formation after perforating, it may cause permeability damage radially away from the perforation. The extent of radial permeability damage is determined by numerous factors including the initial formation permeability, the pressure differential between the wellbore and reservoir, the amount and type of clay and other debris present within the formation pore throats, the liquid-phase chemical components, and the solid-phase chemical and physical characteristics. The most commonly used wellbore fluid for perforating is completion brine. When losses of completion brine are significant, based either on fluid volume or cost of the fluid being lost, a secondary fluid system typically referred to as a fluid-loss control pill (FLCP), or kill pill, is placed across the perforated interval to seal the perforations against further losses. Most often, these postperforation FLCPs contain a mix of liquids and solids, the solids being polymers and particulates such as calcium carbonate [CaCO 3 ] sized to minimize fluid loss to the formation. As leakoff occurs within the perforation tunnel, the solid and liquid phases of these fluids separate as they are filtered across the formation face (previous page, bottom). Fluid leakoff into the formation can reduce permeability through several mechanisms. The substances contained in the leakoff fluid may react with clays in the formation-pore throats causing them to swell or mobilize, thus reducing effective permeability. Compounds such as surfactants and polymers migrating into the reservoir can change pore-throat wettability and effective diameter, thus altering frictional pressures and possibly limiting hydrocarbon flow. As the liquid phase leaks off into the formation, solids and polymers in the perforating fluid are deposited within the perforation tunnel and formation, forming a low-permeability filter - cake, or seal, between the tunnel wall and the formation. In permeable rock, the speed with which this seal builds, along with the charac - teristics of the sealing materials, deter mines the leakoff rate, the total fluid volume lost into the reservoir rock, and inevitably, the level of postperforation formation damage. Realizing the importance of minimizing formation damage created during leakoff, Hydro, Schlumberger and MI-SWACO engineers began research in 21 aimed at developing an optimized perforating fluid to help minimize postperforation formation damage in over - balanced environments. 6 To establish a baseline for perforation-fluid damage, engineers first evaluated water-base and oil-base completion fluids typically used for overbalanced perfor - ating. Initial fluid formulations were designed in close collaboration between Hydro Oil & Energy and MI-SWACO at Hydro s laboratory in Bergen, Norway. The test fluids were blended and shipped to the MI-SWACO laboratory in Houston for verification of the fluid properties. Then, samples were taken to the Schlumberger Reservoir Completions Technology Center (SRC) in Rosharon, Texas, where the perforation tests were conducted. At the Rosharon facility, six fluid types were evaluated in a test cell using various configura - tions (below). Since zinc-cased shaped charges have been shown to be incompati ble with certain water-base completion fluids, several of the test fluids were evaluated with both zinc and steel casing materials. 7 The first round of tests was conducted using Castlegate sandstone cores with permeabilities that ranged from 6 to 1, md. In the laboratory, engineers dried the test cores at 3 F [149 C] for 16 hours. These cores were evacuated and saturated with kerosene, and 5. For more on PURE technology: Bruyere F, Clark D, Stirton G, Kusumadjaja A, Manalu D, Sobirin M, Martin A, Robertson DI and Stenhouse A: New Practices to Enhance Perforating Results, Oilfield Review 18, no. 3 (Autumn 26): Chang et al, reference Javora PH, Ali SA and Miller R: Controlled Debris Perforating Systems: Prevention of an Unexpected Source of Formation Damage, paper SPE 58758, presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, USA, February 23 24, 2. Fluid Base fluid Weighting agent Specific gravity, g/cm 3 Solids Oil-base mud Oil-external emulsion Barite 1.65 Barite Cesium formate, lowsolids, oil-base mud Oil-external emulsion Cesium formate/ calcium carbonate 1.67 Calcium carbonate Calcium bromide, lowsolids, oil-base mud Oil-external emulsion Calcium bromide/ calcium carbonate 1.34 Calcium carbonate Potassium formate kill pill Potassium formate Potassium formate/ calcium carbonate 1.63 Calcium carbonate Potassium-cesium formate kill pill Potassium-cesium formate Potassium formate/cesium formate/calcium carbonate 1.63 Calcium carbonate Calcium bromide kill pill Calcium bromide Calcium bromide/ calcium carbonate 1.65 Calcium carbonate > Testing perforating-fluid types. Fluids in the first test series included oil-base fluids and perforating fluids built from completion brines. The density of each was nearly the same, with most being weighted with calcium carbonate [CaCO 3 ]. Spring 27 17

5 Shooting leads Micrometer valve Wellbore pressure 5-gallon accumulator connected to wellbore Gun with shaped charge Simulated wellbore Wellbore pressure data Confining pressure data Shooting plate simulating casing and cement Core sample Perforating fluid Perforation Steel to simulate casing Confining chamber 3-gallon accumulator Wellbore-pore pressure differential Simulated reservoir core samples > Full-scale perforating test instrumentation. The test cell (top left) is shown with the core enclosed in an elastomer sleeve. Once the instrument is sealed, pressure and temperatures are controlled at simulated downhole conditions. Small and large accumulators provide far-field, or hydrostatic, pressures (bottom diagram). During tests, the perforating gun (red) is fired through a steel plate backed by cement into the formation core, thus simulating wellbore conditions (inset). Core Cement an initial porosity was measured. Technicians established permeability in both axial- and diametral-flow geometries under ambient temperature and pressure to simulate overburden pressure. The core was then loaded into the perforating vessel with casing and a cement plate attached to the face of the core (left). Overburden stress was applied to the core, the gun assembly installed and the simulated wellbore filled with the test fluid. Most of the tests involved rotating the test cell so that the guns fired vertically to simulate oriented perforating in a horizontal well. Once the test cell reached the desired reservoir temperature, pore pressure, overburden stress and wellbore pressure were applied to create an overbalance of 45 psi [3.1 MPa]. Once all pressures had stabilized, engineers fired the guns, and allowed wellbore- and pore-pressure readings to restabilize. Technicians shut in the system and maintained an overbalanced condition for three days. On some tests, leakoff continued during the shut-in period, causing the wellbore pressure to decrease and approach reservoir pressure (next page, top left). If the pressure dropped to a predetermined level, technicians increased the pressure to maintain a 45-psi overbalance. This procedure simulates field operations in which the hydrostatic column in the wellbore is topped off periodically to maintain hydrostatic pressure. In some of the tests, this pump-up and leakoff cycle occurred several times throughout the shut-in period as a function of the perforating fluid s ability to control fluid loss. After three days, the system was allowed to cool and pressure was reduced to atmospheric levels. Postperforating productivity was measured at ambient temperature by flowing kerosene through the core in the axial direction. Starting from a low flow rate, production continued until steady-state flow was established. Then, the flow rate was increased to measure the incremental cleanup as a function of flow rate. To compare the loss-control characteristics of the various fluids tested, engineers determined the rate at which the filtercake builds, which can also be interpreted as a leakoff rate (next page, top right). Technicians also captured data from conventional high-pressure, high-temperature, (HPHT) fluid-loss tests. The volume of filtrate captured during the first minute of the test, or spurt loss, also helped in comparing the filtercake-building characteristics of the different fluids (next page, bottom). 18 Oilfield Review

6 Pressure, psi 6, 5, 4, 3, 2, 1, 5, 4, > Typical shut-in pressure profile. A wellbore-pressure profile was acquired during a 72-hour shut-in period. The pressure spikes occurred when technicians increased the simulated hydrostatic pressure to account for fluid leaking off into the core. The rate of fluid leakoff is derived from the slope of the leakoff curve (inset). Pressure differential (Pwellbore Ppore), psi Square root of time, s 1/2 > Fluid leakoff rate. The pressure differential between wellborehydrostatic pressure and pore pressure just after wellbore pressure has stabilized is plotted against the square root of time. Normalized for variations in the surface area of the perforation-tunnel wall, the slope of the line indicates the rate at which the filtercake builds. This value can also be interpreted as the leakoff rate, indicating the volume of fluid leaking into, or through, the core over time. Test number Initial permeability, md Axial Diametral Core porosity, % Wellbore fluid, specific gravity, g/cm 3 Perforating direction (charge) HPHT leakoff at 1 min, ml Leakoff rate, psi/s 1/2 /in. 2 CFE NPPR Oil-base mud (1.65) Horizontal (zinc) Oil-base mud (1.65) Up (zinc) , Calcium bromide, low-solids oil-base mud (1.34) Up (zinc) Cesium formate, low-solids oil-base mud (1.67) Up (zinc) , Calcium bromide kill pill (1.65) Up (zinc) , Calcium bromide kill pill (1.65) Up (steel) Cesium formate kill pill (1.63) Up (zinc) Cesium formate kill pill (1.63) Up (steel) Potassium-cesium formate kill pill (1.63) Up (zinc) Potassium-cesium formate kill pill (1.63) Horizontal (zinc) Zinc Steel Spurt Leakoff CFE NPPR Test 9 Water Test 4 Oil Test 8 Water Test 1 Water CFE Test 5 Test 6 Water Water Test 1 Oil Test 7 Water Test 3 Oil Test 2 Oil > Initial results from the first series of 1 tests (top). Tests 1 and 2 compared perforations shot using oil-base perforating fluids with perforations shot in the horizontal and vertical directions. A significant improvement in core-flow efficiency (CFE) was seen with the guns oriented vertically. In Tests 5 and 6, fluids built from calcium bromide [CaBr 2 ] were tested with steel- and zinc-cased charges, confirming the negative impact of bromine and zinc in solution (bottom left). The normalized perforation/permeability ratio (NPPR) was improved with steel-cased charges. Also of note is the CFE comparison between water- and oil-base fluids. With the exception of Test 4, perforating in oil-base fluids produced the least damage (bottom right). Engineers suspect that the low-solids, oil-base mud used for Test 4 suffered a broken emulsion and therefore produced poor CFE values relative to the other oil-base fluids tested. The high CFE produced in Test 7 with water-base fluid is not completely understood. Because water-base CFE values this high are inconsistent with all other water-base tests, engineers considered this test an anomaly. Spring 27 19

7 Data from the test series indicated that most of the fluids slowed the egress of filtrate into the core. However, calcium bromide [CaBr 2 ] brine and low-solids oil-base mud (LSOBM) formulated with cesium formate [CsCOOH] brine were exceptions. Previous tests had shown that a chemical reaction occurs between the zinc debris and calcium-containing brine during perforating with zinc-cased charges. This typically causes the CaBr 2 perforating fluid to lose its fluid-loss control capability as illustrated by the immediate equalization between wellbore and pore pressures (right). 8 However, fluid-loss control is maintained when steel-cased charges are used. The CsCOOH-base LSOBM demonstrated less fluid-loss control capability. A high initial fluid loss was observed, and more fluid entered the formation, particularly during the initial spurtloss phase. When examining the cores after the tests, the research team noted that the perforation tunnels were filled with material, and in some cases, tightly packed with solids from the perforating fluid and formation sand grains. This material in the tunnel may have acted as a porous medium within a tunnel of otherwise nearly infinite conductivity. To further understand the cleanup potential of the various fluids, engineers calculated a perforation permeability that takes into account the packing of filtercake material within the perforation tunnel. The team used a numerical simulator to calculate perforation permeability based on measured productivity and perforation-tunnel dimensions. Once perforation permeability was obtained, a normalized perforation/permeability ratio (NPPR) was defined by dividing the perforation permeability by the root-meansquare of core axial and diametral permeability. 9 The NPPR provides a measure of how permeable the perforation is in comparison with the original rock permeability. The measurement is independent of the length and diameter of the perforation tunnel. Data from the NPPR calculations confirmed that using oil-base perforating fluids results in cleaner perforations (next page). It also provided a tool to help evaluate the cleanup efficiency of the waterbase perforating fluids not otherwise defined by core-flow efficiency (CFE) calculations. 1 The data further demonstrated the direct relationship between fluid-loss control and productivity impairment. The less effectively a perforating fluid builds filtercake, the more Pressure, psi Pressure, psi 6, 5, 4, 3, 2, 1, 6, 5, 4, 3, 2, 1, > Charge-casing interference with fluid-loss additives. Engineers suspect that powderized zinc from the zinc-cased charges reacts with salts in brinebase perforating fluids. These reaction products negatively affect polymers used for fluid-loss control in perforating and kill fluids. Leakoff-pressure data demonstrate the lack of fluid-loss control with zinc-shaped charges (top); wellbore (green), near- (blue) and far-pore (orange) pressures are equal, indicating the absence of a filtercake and fluid-loss control. With steel-cased charges (bottom), the fluid is able to build a filtercake; wellbore (green) and pore (orange and blue) pressures are easily differentiated. damage it will create; this is particularly true of water-base fluids. In general, the greater the volume of fluid lost to the formation, the more concentrated and dehydrated the internal and external filtercake becomes. Thus, the filtercake is more difficult to remove during production and causes more damage to the perforation tunnels. When waterbase perforating fluids are used, the NPPR declines log-linearly with the leakoff rate, demonstrating the inefficiency of filtercake removal as well as the adverse relative permeability effect caused by water-base fluids. The LSOBM fluid tests showed higher leakoff volumes that could be expected to impair productivity. However, despite their higher leakoff rate and higher HPHT values, the LSOBM fluids tested do not significantly impair Zinc-Cased Charge Steel-Cased Charge Wellbore pressure Far-pore pressure Near-pore pressure Wellbore pressure Far-pore pressure Near-pore pressure permeability, as long as the oil-base fluids are stable and maintain their oil-external emulsions throughout the perforating process. The ability to measure simulated wellbore and formation pressures helped engineers understand the fluid dynamics of leakoff, and the potential damage caused by perforating. Results of this first series of tests indicate that, with either water- or oil-base perforating fluids, the key to minimizing permeability damage is rapidly building a high-quality filtercake across the perforation-tunnel formation face. Although oilbase perforating fluids demonstrate superiority to water-base fluids in reducing formation damage, minimizing fluid loss should still help reduce productivity impairment. 2 Oilfield Review

8 NPPR 1, 1, Leakoff rate, psi/s 1/2 /in. 2 > Calculation of perforation permeability. The normalized perforation/permeability ratio (NPPR) helps engineers compare true formation permeability with that of the rock after perforating. It is also useful in differentiating the various fluids tested. The goal is to achieve a high NPPR. Oil-base fluids (blue diamond, red square and brown triangle) show a distinct advantage over the water-base fluids evaluated. Simulating Field Conditions Although the first test series clarified the efficacy of various fluids in the laboratory, there were unanswered questions about perforating strategies in the field. Since perforating procedures vary from one project to the next, is simply using a low fluid-loss perforating fluid all that is necessary to ensure minimal permeability damage? Should wells be perforated in clear brine or a fit-for-purpose perforating fluid? Should isolation packers be used to help optimize dynamic underbalanced conditions? To answer these questions, researchers designed a second series of tests to evaluate the performance of water- and oil-base perforating fluids under varying simulated field conditions. Several simulation scenarios were designed to replicate conditions that might exist in the field for example, perforating in an open well, OBM CaBr 2 kill pill (KP) KCOOH KP (K/Cs)COOH KP CaBr 2 LSOBM CsCOOH LSOBM Trend line for water-base fluids in an isolated wellbore, and with a clear fluid. 11 In the first, the quick-kill process, a wellbore open to the surface was perforated while filled with a specially designed solids-laden perfor - ating fluid. Simulated hydrostatic pressure from the far-field wellbore fluid provided the energy source to quickly increase downhole pressure to the desired overbalanced state. In the second scenario, the slow-kill process, a wellbore was perforated overbalanced, but isolated below packers. After perforating, the dynamic pressure effect of gun firing immediately reduced the wellbore pressure after charge penetration. Without access to the full hydrostatic column, however, the isolated section of the wellbore cannot return to an overbalanced state until the packers are manually unset. Last, in a variation called kill later, the test cell was configured to simulate overbalanced perforating in a clear completion fluid. After perforating, the clear fluid was displaced by a kill fluid similar to the perforating fluids used in the previous tests. The weight of the kill fluid effectively bull - headed, or forced under pressure, the clear fluid into the formation until the kill fluid reached the perforation to build a filtercake. Engineers simulated these processes in the laboratory. Fluid accumulators with gas caps acted as the hydrostatic column that provided far-field pressure effects above the perforated zone. A large accumulator volume represented perforating in an open well so that sufficient wellbore fluid and energy were available to replenish the pressure deficit around the perforated section after the guns were fired. Conversely, a small accumulator volume represented perforating in an isolated wellbore; it extended the dynamic underbalance period because there was insufficient energy to replenish the pressure deficit immediately after charge penetration. In the kill-later test, a clear completion fluid was added to the test cell. A piston accumulator filled with the kill fluid was connected to the test cell, but isolated by a valve in the closed position. The accumulator pressure was increased to the wellbore pressure so that there was no pressure loss in the test cell when the valve was opened; this procedure immedi - ately established an overbalanced condition. Once the guns were fired, the wellbore pressure and pore pressure reached equilibrium. The valve between the kill-fluid accumulator and the test cell was opened, and an overbalance was applied to displace the clear fluid through the core sample. Once a filtercake built up, the leakoff ceased and a stable overbalance was maintained. During the kill process, a large volume of clear perforating fluid was pushed into the core, causing the pore pressure to increase. A bleed-off valve on the back side of the core allowed technicians to maintain a relatively constant pore pressure. 8. Chang et al, reference NPPR = where k = permeability. 1. Core-flow efficiency (CFE) is defined by the ratio of the measured productivity index (PI) (after the core is penetrated by a shaped charge) to a theoretical ideal PI (as if the perforation tunnel and surrounding formation were free of any perforation damage). 11. Chang FF, Mathisen AM, Kågeson-Loe N, Walton IC, Svane G, Midtbø RE, Bakken I, Rykkje J and Nedrebø O: Recommended Practice for Overbalanced Perforating in Long Horizontal Wells, paper SPE 94596, presented at the SPE European Formation Damage Conference, Scheveningen, The Netherlands, May 25 27, 25. Spring 27 21

9 6, Quick Kill 1.2 CFE 5, 1. Pressure, psi 4, 3, 2, CFE, PImeasured/PIideal , Quick Kill Slow Kill Kill Later Pressure, psi Pressure, psi 6, 5, 4, 3, 2, 1, 6, 5, 4, 3, 2, 1, Slow Kill Kill Later > Core-flow efficiencies. Castlegate sandstone was perforated using the quick-kill, slow-kill and kill-later processes. For quick- and slow-kill tests, the gun was fired with oil-base perforating fluid in the test cell. For the kill-later process, firing occurred with clear kerosene in the cell that was later displaced with oil-base kill fluid. The pressure (green) for quick-kill shows a low leakoff rate and a minimum number of pump-up cycles (top left). The slow-kill process required more frequent pressure adjustments (middle), while in the kill-later process, fluid-loss control could not be achieved until the clear kerosene fluid was displaced by an oil-base kill pill (bottom). Core-flow efficiency (CFE) calculations show that the quick-kill process using oil-base perforating fluid causes the least amount of permeability damage (top right). CFE calculations for each perforating strategy indicated that the lower the fluid loss during the shut-in period as shown by the shut-in pressure behaviors, the higher the CFE (left and above). An appropriately designed perforation in a well open to hydrostatic pressure would be expected to cause less formation damage than a perforation with the same fluid in a wellbore isolated from hydrostatic pressure. Further, perforating with clear brine and then displacing to a heavier fluid capable of killing the well, often called a kill pill, appears to cause the most damage, probably due to excessive brine loss into the formation. Engineers conducted similar tests using Castlegate sandstone to evaluate the perfor - mance of oil-base perforating fluids. When compared with the water-base fluids, the oil-base fluids showed generally the same trend but with higher CFEs, indicating less formation damage. The data show that perforating with an oil-base fluid in a well open to the surface produces the least damage of all the fluids and methodologies tested. Engineers noted that perforating in oil then later killing the well caused more damage, again demonstrating that rapid filtercake development is necessary to minimize invasion of damaging solids and fluids into the formation. For all tests, there was a consistent trend showing that perforating pressure dynamics influence fluid-loss control behavior for all types of kill fluids. The shut-in pressure profile for perforating an open well showed good filtercake competency. The shut-in pressure profile in an isolated wellbore showed less filtercake competency, as indicated by the need to replenish pressure more often during shut-in. When the simulated wellbore was perforated with a clear fluid and then killed later, poor fluid-loss control was observed. Finally, during tests of perforating without dynamic underbalance, the fluid-loss 22 Oilfield Review

10 No Underbalance Shot with Underbalance Overbalance and underbalance pressure, psi No Underbalance 2,5 2, 1,5 1, 5 5 1, 1,5 2, 2, Time, s 1. Pressure, psi 6, 5, 4, 3, 2, 1, No Underbalance > The importance of underbalance. In this test, Castlegate sandstone was perforated without achieving a dynamic underbalance (top left). Although the leakoff-pressure profile (bottom left) shows wellbore pressure (green) well above pore pressure (orange), indicating good fluid-loss control, the low leakoff rate is attributed to failure to clear perforation debris from the tunnel after perforating. Computerized axial tomography (CAT) scan images (above) show a solid, high-density mass (white) in the perforation tunnel. For comparison, a similar core was perforated using the same fluid design, but dynamic underbalance was achieved with a higher core-flow efficiency (above right). The gray coloring in the perforation tunnel indicates that significantly less debris is left in the tunnel. control was achieved by debris plugging. Although adequate fluid-loss control was obtained without dynamic underbalance, the return permeability suffered from the debris left in the perforation tunnel (above). Once all tests were complete, engineers and scientists at the Hydro Oil & Energy Research Center in Bergen performed petrographic studies on thin-section samples of the cores and observed the changes in grain and pore structures between the crushed zone near the perforation tunnel and the undisturbed sandstone matrix away from the perforation tunnel. In addition, they studied polished epoxyimpregnated samples by scanning electron microscope (SEM) and analyzed micrographs of backscattered images. The thin-section images from the rock adjacent to the perforation-tunnel wall revealed the effect of pressure dynamics on perforation cleanup (right). It was apparent that the shaped charges created a crushed zone near the perforation-tunnel wall. For both the quick- and BR BR BR BR ORSPR7_Don_ThinSec_1 BR BR BR BR A. Slow kill B. Quick kill C. No underbalance achieved > Changes in porosity. Image sets A, B and C (bottom) are thin-section samples cut from lowpermeability Berea sandstone cores (top). The cores were perforated using oil-base fluids. Images A and B show a low content of fine material compared with Image C, indicating that the crushed zone was removed by the dynamic underbalance achieved in the perforation process. Sample A shows higher damage due to higher fluid loss resulting from the slow-kill process. Sample B shows slightly more fine material in the thin section; however the quick-kill process helped clear the perforation tunnel. Image C shows a high content of fine material and no removal of the crushed zone from the perforation tunnel because dynamic underbalance was not achieved. Results of these tests were consistent with those performed on higher permeability Castlegate sandstone. Spring 27 23

11 CFE, PImeasured/PIideal CFE, PImeasured/PIideal Castlegate Sandstone KCOOH KP KCOOH KP Berea Sandstone KCOOH KP OBM OBM OBM > Choosing a perforating fluid. Core-flow efficiency for each fluid tested is shown by process and sorted by core-flow efficiency (CFE). In Castlegate sandstone (top) and Berea sandstone (bottom), an oil-base perforating fluid combined with the quick-kill process (purple) and dynamic underbalance produced the most favorable results; higher CFE values indicate the least amount of perforation damage. The kill-later process (blue) and tests in which dynamic underbalance was not achieved (yellow) were the most damaging. slow-kill cases, dynamic under balance was achieved and the crushed zone was removed. Laboratory studies showed little difference in grain sizes in the two cases. However, in the slowkill case, the higher fluid-loss levels may have caused the increased level of observed damage. In the case with no dynamic underbalance, the crushed zone was not removed. The result was retention of a significant amount of finegrained material in the perforation tunnel, thus reducing CFE. Based on the collected data and petrographic observations, the research team concluded that there is a delicate balance between the degree of cleanup in the perforation and the susceptibility of the perforation to perforating-fluid invasion. Creating a perforation tunnel that is sufficiently clean to allow effective filtercake to build may be more beneficial to overall damage prevention OBM OBM OBM OBM Sized Salt Sized Salt Quick kill with dynamic underbalance Slow kill with dynamic underbalance Kill later with dynamic underbalance No dynamic underbalance Sized Salt Sized Salt than trying to create the cleanest perforation, possibly resulting in more filtrate loss to the formation. Examination of polished epoxyimpregnated SEM samples provided further evidence that achieving a dynamic underbalance during overbalanced perforating is necessary to minimize permeability damage. Data from these extensive studies show that during overbalance, the characteristics of the perforating fluid, the method used to kill and isolate the perforation zone and success in achieving dynamic underbalance during the perforation process strongly influence final well productivity (above). An optimized strategy for overbalanced perforating must include an appropriate perforating fluid capable of rapidly building a filtercake, while achieving dynamic underbalance during the process. In the Field with a Quick-Kill Perforating Fluid China National Offshore Oil Corporation (CNOOC), Chevron and Eni, the field operator, are partners in the development of the HZ oil and gas fields, operating as the CACT Operators Group in the South China Sea. The HZ fields primarily consist of stacked, thin sandstones in which sufficient single-well productivity can be achieved by commingling production from multiple sandstones, by drilling horizontal wells, or both. Traditionally, tubing-conveyed perforation (TCP) has been preferred for thick production zones. However, CACT engineers found that wireline-conveyed casing guns are an economic alternative for thinner production zones that are spread over a large interval. 12 In these wells, multiple wireline-conveyed casing-gun operations are usually performed slightly overbalanced because it is operationally easier and safer. Previous perforating operations using tubingconveyed underbalanced-perforation methods and static underbalanced wellbore pressures have required additional rig time, and operations have been complicated. In many instances, static underbalanced perforating has delivered underperforming wells, probably because the perforation-induced skin has not been adequately removed. Further, when TCP is used, unless sufficient rathole is drilled to allow dropping the guns to the bottom of the wellbore, the well must be killed to retrieve them, creating the risk of postperforation completion-fluid invasion damage. To minimize cost, simplify operations and minimize perforation damage, CACT elected to perforate most new wells and reperforate existing wells overbalanced using wireline casing guns. After studying candidate wells, the CACT reservoir and production department, working with Schlumberger and MI-SWACO engineers, elected to test two new completion technologies for overbalanced perforating: the PURE system and the CLEANPERF fluid, a noninvasive perforating fluid. These technologies were expected to improve well-completion efficiency. To test the new perforating system design, engineers planned to compare the recompletion results on reference Well 1 with those obtained from the newly completed Well 6. Pressurebuildup data were not available from reference Well 1, so the productivity index (PI) was analyzed to estimate its completion skin factor. A PLT Production Logging Tool was run in the well after completion to determine the flow rates of 24 Oilfield Review

12 all the layers when water cut was lowest. PLT evaluation of the reference well for the four layers perforated using wireline-conveyed guns and the PURE system at an overbalance of about 1.3 MPa [188 psi] indicated permeabilities from 9.4 to 1,65 md, and skin factors from to.97. Although reference Well 1 and Well 6 were perforated using the PURE system, each was shot using a different perforating fluid. In reference Well 1, engineers used CLEANPERF fluid system, while Well 6 was perforated using a typical polymer kill pill. M-I SWACO designed the CLEANPERF fluid system for use with the Schlumberger PURE perforating system, primarily in overbalanced perforating situations. The perforating fluid provides a low-permeability barrier that limits deep invasion of solids and fluids into the reservoir along the perforation tunnel immediately after perforating. To further help minimize postperforating damage, the system readily flows back without a remedial treatment during production. CLEANPERF fluids are designed for each specific application based on several criteria including formation characteristics and expected pressure differentials. Critical to each design are providing adequate density for the required overbalance; quickly establishing a thin, low-permeability seal across the formation face; allowing development of minimal adhesive and cohesive forces within the seal to promote uniform release from the formation and removal during flowback; maintaining thermal stability for the period of time in which the system is in the wellbore prior to production; and being chemically compatible with perforation charges. Data from thin-section analyses of core material provided by CACT helped engineers design an appropriate blend of bridging agents to effectively seal the full range of pores present in the formation. Engineers elected to use a waterbase CLEANPERF system for Well 1. The perfor - ating fluid was formulated using 4.21% by volume of sized bridging agents and two different clayinhibition additives. To assist with filtercake cleanup, chemicals were added to reduce the adhesion of the filtercake to the wall of the perforation tunnel. The fluid also contained a biopolymer viscosifier, a starch-based filtrationcontrol additive, and stabilizers for ph and microbial activity. 12. Pizzolante I, Grinham S, Xiang T, Lian J, Khong CK, Behrmann LA and Mason S: Overbalanced Perforating Yields Negative Skin Values in Layered Reservoir, paper SPE 1499, presented at the SPE International Oil & Gas Conference and Exhibition in China, Beijing, December 5 7, 26. Completion skin value Reference Well 1 Well 6 2. > Improving skin with a fit-for-purpose perforating fluid. Data from field test and PI calculations show that for reference Well 1 perforated with CLEANPERF fluid, the actual results (purple) matched planning estimates (green). By comparison, results from Well 6, perforated with a conventional kill fluid, were 48% below modeled optimal results. In the field, engineers perforated Well 1 using the PURE system and the CLEANPERF fluid, and then compared perforation efficiency results with those in Well 6. Measured completion skins were evaluated against completion skin values modeled using the SPAN Schlumberger perforating analysis software. The benchmark was set at the technical limit for perforation efficiency defined by modeling the perforation-completion skin of a fully cleaned crushed zone. Engineers compared the measured completion skin for reference Well 1 from the PI equation with that of Well 6 from multilayered reservoir testing. The modeled ideal completion skin value for reference Well 1 was approximately 1.38, while the simulated completion skin based on field results was 1.37; this was close to ideal. The modeled ideal completion skin for Well 6 (Layer A 4) was approximately 1.85, while the simulated completion skin based on field results was.97, indicating that the completion skin was 48% below the modeled optimal results (above). Data from both wells were carefully sorted and analyzed. Taking into account the significance of laboratory data (discussed earlier in this article), engineers concluded that since both wells were perforated using the PURE system and all other parameters were relatively equal, there was a strong likelihood that the improved completion efficiency of Well 1 was due to use of the noninvasive CLEANPERF perforating fluid. 48% Modeled optimal results Actual field results The Third Element of Perforation Design Although field data are still somewhat limited, the research presented in this article suggests that engineers now have the necessary tools to formulate an optimized perforation strategy. As with many E&P activities, the man-made fluids present in the borehole during completion operations have a direct effect on ultimate efficiency and productivity. Properly designed, fit-for-purpose perfora - ting fluids show great promise in helping operators improve the return on their perforating investments. There is little doubt that the elements of an optimized perforating strategy optimal perforation-gun orientation, dynamic underbalanced perforating and new perforating fluids will grow in time. But for now, the addition of fit-for-purpose perforation fluids provides an easily adoptable step-change in the design and execution of modern perforating techniques. DW Spring 27 25