Quick clean up and dramatic improvements in reservoir producibility have been achieved in gas wells located offshore Egypt. These wells were drilled and completed using an engineered drill-in fluid system. The fluid formulation was carefully designed and extensively tested in three different laboratories prior to the field applications to help ensure reproducibility of the data and to verify the non damaging characteristics of the fluid. These tests were conducted under simulated downhole conditions to help ensure fluid compatibility with the reservoir rock minerals and natural fluids. To help minimize fluid invasion while drilling in the payzone section, the optimal concentration and particle size distribution (PSD) of the suspended bridging material were selected and maintained during the field applications. The PSD of pure ground marble was selected based on the reservoir rock morphology and average pore size to establish effective bridging near the wellbore and help ensure quick lift-off of the filter cake. A high-density calcium chloride / calcium bromide brine blend (14–14.5 lb/gal ~ 1.68 sp.gr.-1.74 sp.gr.) was used as the base fluid to achieve and maintain the required fluid density without additions of insoluble weight material. Optimal concentrations of non-damaging temperature-stable polymers were used to provide suspension and filtration control. The gas reservoir section was drilled and completed in several wells with the new system. Productivity index and flow rates exceeded the operator's expectations without any stimulation treatments. Substantial savings were realized in terms of rig time and well completion costs. This paper presents the laboratory and field-generated data and discusses the key issues in designing and monitoring the new drill-in fluid during the field applications. Introduction One of the keys to optimizing wellbore connectivity and retaining the natural reservoir rock permeability is to ascertain and quantify the complex, often interdependent physical interactions and chemical reactions occurring downhole between the reservoir rock fluid and minerals and the drill-in / completion fluids used 1,2,3. Some of the most common ways of damaging a formation include pay zone invasion and plugging by fine particles, formation clay swelling, commingling of incompatible fluids, movement of dislodged formation pore-filling particles, changes in reservoir rock wettability, and formation of emulsions or water blocks. Once one of these damage mechanisms diminishes the permeability of a reservoir, it is seldom possible to restore it to its original condition. Reservoir characterization and sensitivity studies were carried out to identify and quantify the geologic parameters that could influence the producibility of the Miocene sandstone gas reservoirs in an offshore field in Egypt. The field is located in the Mediterranean Sea, 35 miles north of Port Said City, at the northern entrance to the Suez Canal (Figure 1) The fluid sensitivity study included thorough examination of the rock morphological and mineralogical composition 4,5. Core analysis data was generated by specialized core laboratories for core plugs from carefully selected sections of the gas zones. The natural reservoir fluid was also analyzed to establish their chemical make-up. These data helped determine the reservoir's potential for formation damage problems. Based on the information and the reservoir rock data, a brine-based drill-in and completion fluid was designed and tested, under simulated downhole conditions. These tests were conducted in Baroid's Houston lab, Baroid's Cairo lab, and Eni E&P Milan lab to ensure reproducibility of the lab test data and verify the non damaging characteristics of the selected additives and fluid formulation.

Excessive loss of high-density brines into the formation has always been a major concern during completion operations, since it leads to formation damage and well control issues. The problem becomes more complex at high temperatures and when the treatment involves running gravel-pack assemblies and downhole sand screens. Typically, the fluidloss-control pills are composed of very high concentrations of crosslinked polymers with or without bridging particulates. The sealing mechanism of these pills is a combination of viscosity, solids bridging, and polymer filter-cake buildup on the porous rock. Due to the instability of polymers at high bottomhole temperatures, incompatibility with some divalent brines, and the necessity to cleanup with acid, a new solids-free lost-circulation pill that is stable for prolonged periods at high temperatures was developed. This paper introduces the development and the first field application of a new solids-free non-damaging viscoelastic surfactant-based fluid-loss pill (VES-PILL). The single-additive system forms a "gel" with most completion brines currently used in well operations. Laboratory data demonstrate that this pill could be used up to 375°F. The "gel" structure of this system sustains viscosity high enough to effectively control or stop brine-loss, while maintaining a safe differential pressure into the formation. Several "frac and pack" completions were performed for the first time in Saudi Arabia in the Pre-Khuff sweet-gas zones. The VES-PILL was used to prevent losses after perforating, fracturing and gravel-pack operations. The pill was used in the field up to 310°F, and brine-loss was effectively controlled for more than 3 days. The effectiveness of the pill was also demonstrated by a five-fold increase in surface pumping pressure during placement. The wells were produced at rates exceeding expectations without further remediation to cleanup the fluid-loss pill. Background Fluid-loss control is very important in successful well completion operations. Loss of completion and workover fluids is unacceptable due to economic (expensive heavy brines), technical or safety reasons (formation damage, hole collapse and well control issues).1 Loss of dense brines into the productive zones is highly damaging, especially to high permeability formations. It is very difficult to unload heavy brines once losses have occurred. Because of the high-density of brines used, stratification tends to further inhibit its removal.2 Calcium and zinc bromide brines can form stable acid insoluble complexes when reacted with some formation brines.3 Hence, the most effective means of preventing the formation damage is to limit completion brine losses into the formation by either chemical or mechanical means. It is best to avoid the use of fluid-loss control pills by incorporating mechanical fluid-loss control devices into the completion string whenever possible.4 However, in the absence or failure of such devices, or in situations where they cannot be used, chemical fluid-loss pills are required. The use of a pill is normally required before and after sand control treatments and after perforating. In these treatments, the pill is spotted into the perforations or against the sand control screens. In addition, fluid-loss control pills are required in several workover operations that need temporary zonal isolation. There are several reviews on the use of different types of fluid-loss pills5–7 and guidelines on the selection of the pill.4,8 A variety of fluid-loss control pills have been used in the industry, such as foams3, oil-soluble resins3, fibers,5,9 acid soluble particulates,3 graded salt slurries,10 high concentrated linear11 and crosslinked1,6,1,13 non-biopolymers14 and bio-polymers.10,15 The polymer systems are very effective in fluid-loss control as long as the temperature limit of the specific polymer is not exceeded. One of the important features of any fluid-loss pill is its ability to maintain viscosity under bottom-hole conditions (especially high temperature). The viscosity reduction of gel at high temperatures is either due to the degradation of polymer or reduced molecular interations.16 The viscosity will not be regained on cooling if there is molecular degradation at high temperature.

High-density water-or oil-based muds are not stable suspensions. Laboratory corrosion data and field observations suggest that solids-free, inhibited high-density brines could be ideal packer fluids for deep, hot wells. Expensive washover and fishing operations required for recovery of tubing stuck in settled mud solids could be eliminated. 2. Fluids must not deteriorate packer elastomers. 6 3. Fluids must remain pumpable during the life of the well; i.e., no high gelation or solidification may develop over time. 3,4 4. Fluids must not cause corrosion (inside casing or outside tubing).5. The fluids must not damage the producing formation because they may contact these producing zones during completion or workover operations. 3Water-based drilling-mud organic additives degrade upon prolonged exposure to high temperatures and sometimes generate corrosive gases, such as CO 2 and H 2 S. 3-5 Bacterial activity could also break down organic materials and/or produce corrosive elements.Lignosulfonate solutions can react electrochemically at metal surfaces to form sulfides, even at moderate temperatures. 3,4 Properly formulated oil-based muds are nonconductive and should not cause corrosion. 4 In case of packer failure or leaks, however, produced oil or gas dissolves in oil mud and destroys the suspension properties, allowing the weighting material (barite) to settle on top of the packer and to cause stuck packer and tubing.

On December 8,1989 the Sidki production platform was struck and severely damaged by a cargo ship that had ventured outside the shipping lanes in the southern Gulf of Suez. The collision rendered the platform a total loss, and all wells had to be plugged and abandoned. The Sidki field production rate at the time of the accident was 6750 BOPD and 2836 SCF/STBO gas-oil ratio (GOR) from six active wells with three wells shut in. Redevelopment commenced in 1993 with the setting of a new platform and initial plans to drill nine replacement wells to recover an estimated remaining 19.2 MMSTBO (to January 2006). But rather than simply redrill the existing wells, engineers examined ways to improve the redevelopment plan and optimize the remaining oil recovery from the Nubia reservoir. This paper discusses how one company applied advanced engineering methods to optimize this redevelopment. Engineers systematically evaluated the static reservoir conditions found during drilling of the first three redevelopment wells, and then improved oil production rates and recovery by placing four additional 2000 foot horizontal wells at strategic locations. Through re-engineering the new field development, the very accident that so spectacularly destroyed the platform ultimately yielded a "second chance" for Sidki. Production during June, 1996 now averages 20,092 BOPD from only seven wells. Ultimate primary redevelopment reserves are expected to total 24.5 MMSTBO, with potential waterflooding increasing reserves to 38.6 MMSTBO. Introduction The Sidki field, as shown in Fig. 1, is located in the southern Gulf of Suez, Egypt. The field is also located primarily within the GS 382 concession block, and was discovered with the drilling of the exploratory well GS 382-1A in January 1976. A 12 drilling slot platform, the Sidki "A", was subsequently set in 271 feet of water and production commenced in December 1977. Production from the Sidki platform was abruptly halted on December 8, 1989 when the platform was struck by the errant cargo ship. The collision rotated and tilted the platform deck, ruptured well risers, and the collapsing deck severely damaged several wellheads (Fig. 2). Of the six wells naturally flowing on the platform at the time of the accident, control of only one well, Sidki 5A, was lost due to the failure of the subsurface safety valve to close. Sidki 5A was brought under control within one week, but the platform was considered a total loss and all wells were eventually plugged and abandoned. Two other remote fields which had their production routed through the Sidki platform were shut in as well. Additional details about the accident and emergency response are available in Reference 1. Sidki production is from the Nubia sandstone at an average depth of 10,600 feet subsea. The 1000 foot thick Nubia is tilted at 30 degrees, providing ample opportunity for gravity segregation of reservoir fluids. Reservoir pressure reduction from production and limited aquifer support caused a large secondary gas cap to subsequently develop from the reservoir crest at -9400 feet subsea to -10480 feet subsea. Constant problems with gas coning plagued the Sidki wells from the start of production in 1977 due to this expanding gas cap. Redevelopment planning would have to deal with this problem. Redevelopment work commenced in 1993 to replace the lost "A" platform and wells. With insurance proceeds funding the redevelopment, reservoir engineering plans to enhance ultimate oil recovery and rate had to work within the constraints of the insurance program. P. 231

Summary. An invert emulsion fluid composed of brine (e.g., NaCl, NaBr, CaCl2, CaBr2, and ZnBr2) emulsified into hydrocarbon oil (e.g., diesel, crude, or mineral) was formulated with a mixture of nonionic surfactant emulsifiers. Laboratory investigations were conducted to define the emulsion characteristics and to develop methods for controlling the fluid's rheological properties and emulsion stability at elevated temperatures. This system has oil as the external phase, and the stability of the emulsion in most cases is linked to the homogeneity and fineness of the brine-dispersed droplets. The emulsion stability is also related to its viscosity and to the strength of the interfacial film formed by the emulsifiers that coat the brine droplets. For packer-fluid applications, the solids-free invert emulsions offer several advantages over conventional oil- and water-based muds. For example, the fluid is virtually nonconductive, providing greater corrosion protection than conventional water-based muds and clear brines. It can also provide formation protection characteristics and can solve such problems as clay swelling and solids invasion. This new completion fluid is ideal for perforating, drilling in, under-reaming, and gravel packing. The emulsion can be filtered through a less-than-10- m cartridge filter and can be reclaimed and used again. This new completion fluid was used successfully in the field as a packer fluid and as a perforating fluid for testing a reservoir that was drilled with conventional oil-based mud. Introduction Oil-based muds are nonreactive fluids used for drilling and completion operations instead of aqueous fluids, which create similar conditions to the depositional environment of the rocks penetrated and often fail to stabilize the hole. Oil-based muds are being used to drill stable, in-gauge holes through water-sensitive shales and salt sections. They provide superior lubricating qualities over water-based muds and have proved to be less damaging to water-sensitive producing formations in many fields. Also, oil-based muds do not readily conduct an electric current. Thus, corrosion reactions on metal surfaces are not likely to occur, which is why oil-based muds are the preferred packer fluids, especially for high-pressure/high-temperature (HPHT) wells. Conventional oil-based muds usually contain a large quantity of solids (e.g., organophilic clays and barite). These added solids are necessary to develop the required suspension for the weighting material and to form internal bridging in the rock pores to build a wall cake needed to stabilize the wellbore. One of the most expensive workover operations is the recovery of stuck tubing and packers in settled mud solids. High-density conventional oil-based muds are not stable suspensions when used as packer fluids. Downhole tubing or packer leaks cause mud contamination with the produced oil or gas (gas is highly soluble in oil-based muds). The annulus pressure starts building up and must be bled, which allows more oil or gas influx into the annulus. This typical sequence of events leads to the destruction of the initial suspension properties of the mud and allows the mud solids and weighting material (barite) to settle on top of the packer and around the tubing. Several instances where conventional high-density oil-based packer fluids failed in such a manner have been seen in the U.S. gulf coast and internationally. Subsequent wash-over and fishing operations resulted in numerous days lost and hundreds of thousands of dollars in cost. Drilling water-sensitive pay zones with oil-based muds that have all-oil filtrates is usually recommended. For example, reservoir rocks containing volcanic ash and/or smectite or mixed-layer clays could be permanently damaged if they come in contact with any aqueous fluids. In many cases, these types of reservoirs require gravel packing to minimize sand production problems. Viscosified clean oil has proved to be the most suitable gravel-packing fluid for low-pressure reservoirs. Unfortunately, no oil-soluble material is available to increase the oil's density. For high-pressure reservoirs, either high-density brines or conventional oil-based muds with solids must be used for gravel packing, which causes irreparable formation damage and loss of the zone productivity in some cases. The obvious advantage of perforating, underreaming, and possibly drilling in with solids-free invert emulsions triggered our interest in developing simple methods for formulating this type of completion fluid to control formation damage. Our study objectives wereto determine the optimum oil/brine ratios and the required concentrations of the emulsifier to produce the most stable emulsion at temperatures up to 400F [204C],to develop temperature/viscosity profiles,to select the most suitable oil-soluble polymers for viscosity and rheology control,to define the emulsion contact angle against quartz surfaces and the residual damage in terms of return permeability for Berea sandstone cores,to determine the feasibility of using sized acid- and water-soluble materials for the temporary bridging of high-permeability reservoirs,to study the corrosiveness of the emulsion andto define the filterability of the emulsion.