Chevron has been successfully drilling and gravel packing open hole horizontal wells on the Alba Field (central North Sea) since 1998 and 13 open-hole gravel packed (OHGP) wells drilled with water based mud(WBM) are currently in production with no history of sand production. Although these wells have been hugely successful with significant net present value (NPV) returns it was recognised that the future, mature redrill and infill targets cannot sustain the current costs associated with traditional OHGP completions. The challenge was to develop alternative techniques to maintain the benefits of OHGP wells but to achieve a low cost well and completion concept to assist in realising new drilling opportunities. To drill the shale above the top of the reservoir and the productive interval in a single hole section would remove the conventional requirements to set an additional casing string and change over to a water based system prior to drilling into the reservoir. This would save costs but raise a question over the gravel packing operation. Hitherto, attempts to gravel pack involving á/â placement techniques using an aqueous carrier fluid following drilling with oil based systems have had only limited success. The prospective problems were examined by extensive laboratory tests carried out by Baroid and Chevron in co-operation. A new synthetic oil based mud (SBM) formulation was developed and compatible displacement fluids and procedures were devised. Based on this work, 1500 ft of shale and reservoir were drilled; a liner was installed – predrilled over the reservoir section – and screen was run inside the liner. Gravel was pumped using brine as carrier fluid and complete gravel placement was achieved. The well has achieved productivity levels at least as good as existing WBM wells. A second well completed in the same manner has given similar performance. This combination of a liner system and SBM fluids offers several advantages. There is the prospect of considerable savings with respect to operating time, cementing and drilling fluids. Also the liner gives protection to the screen. This new approach which represents potential large savings in costs and excellent productivity is considered to be very applicable for expandable sand screens (ESS), multi-lateral completions and additional redrill targets both on Alba and worldwide.

The penetration rates of invert oil mud systems in Mancos Shale have been measured using the full-scale wellbore simulator at the Drilling Research Laboratory. Experimental parameters were 1.) weight material type - high specific gravity (ilmenite) vs conventional (barite); 2.) fluid formulation - low colloid type (relaxed filtrate) vs conventional (low filtrate) and 3.) bit type - synthetic diamond insert blank vs conventional (three-cone roller). In addition to laboratory data, field case history data for corresponding systems have been studied. Maximum penetration rates were observed for the minimum solids system, especially when used in conjunction with the synthetic diamond insert bit.

Summary Chevron has been successfully drilling and gravel packing openhole horizontal wells in the Alba field (central North Sea) since 1998, and 13 openhole gravel-packed (OHGP) wells drilled with water-based mud (WBM) are currently in production with no history of sand production. Although these wells have been hugely successful with significant net present value (NPV) returns, it was recognized that the future, mature redrill and infill targets cannot sustain the current costs associated with traditional OHGP completions. The challenge was to develop alternative techniques to maintain the benefits of OHGP wells but to achieve a low-cost well and completion concept to assist in realizing new drilling opportunities. Drilling the shale above the top of the reservoir and the productive interval in a single hole section would require removing conventional requirements for setting an additional casing string and changing over to a water-based system before drilling into the reservoir. This would save costs but raises a question concerning the gravel-packing operation. Hitherto, attempts to gravel pack that involve alpha/beta placement techniques using an aqueous carrier fluid following drilling with oil-based systems have had only limited success. The prospective problems were examined by extensive laboratory tests carried out cooperatively by Baroid and Chevron. A new, synthetic oil-based mud (SOBM) formulation was developed, and compatible displacement fluids and procedures were devised. Based on this work, 1,500 ft of shale and reservoir were drilled, a liner that was predrilled over the reservoir section was installed, and screen was run inside the liner. Gravel was pumped using brine as the carrier fluid, and complete gravel placement was achieved. The well has achieved productivity levels at least as good as existing WBM wells. A second well completed in the same manner has given a similar performance. This combination of a liner system and SOBM fluids offers several advantages. There is the prospect of considerable savings with respect to operating time, cementing, and drilling fluids. The liner also gives protection to the screen. This new approach, which represents potential large savings in costs and excellent productivity, is considered applicable to other types of completions when it is desirable to drill with oil-based mud even though conventional thinking would have called for water-based drill-in fluid. This consideration applies to targets in the Alba field and worldwide. Introduction The Alba oil field, located in Block 16/26 of the U.K. sector of the North Sea, comprises an Eocene sandstone formation that is thin; highly porous and permeable; very unconsolidated; and overlain by a bed of impermeable, highly reactive shale. The nature of the reservoir dictated that development would be best achieved by openhole completions and highly deviated or horizontal reservoir sections with the productive interval located near the top of the sand body. The earliest approach was to run screen-only completions, with SOBM as the drill-in fluid. The next stage of the evolutionary approach involved the same screen arrangements but with a saturated brine/sized sodium chloride-based drill-in fluid. Both approaches provided excellent drilling properties, but there were severe limitations with respect to productivity for the wells drilled with SOBM, and screen longevity was a problem for wells using the sized-salt approach.1 Both issues were addressed by adopting a sized carbonate drill-in fluid and performing openhole gravel packs on the productive sections. From 19981 to July 2001, 13 openhole sections had been successfully gravel packed and are still in production with high flow rates and no history of sand production. However, it was recognized that despite the excellent flow rates and significant NPV returns provided by these wells, the future mature redrill and infill targets could not sustain the current costs associated with traditional OHGP completions. The asset was challenged with developing alternative completion techniques to maintain the benefits of OHGP wells while reducing the costs of current drilling and completion procedures and developing a low-cost well concept to assist in realizing new drilling opportunities. The ability to gravel pack openhole sections drilled with SOBM would enable the shale above the top of the reservoir and the productive interval to be drilled in a single hole section. This would remove the requirement to install an additional casing string and to change over to a different mud system before drilling into the reservoir. For example, in the case of a redrill in Alba W33, there was the prospect of saving a casing run of more than 1,000 ft and using one mud system throughout. Potential total savings with respect to operational time, cementing, and drilling fluids were estimated to be of the order of U.S. $3 million. On the other hand, experience with completions in the Alba field (with the interval drilled with SOBM and the completion fluid as brine) has not been encouraging. During the early stages of the Alba development, several productive intervals were drilled with SOBM and displaced to aqueous completion fluid; the productivity of the wells was much less than expected.1 The gravel-packing technique used in Alba for the previous wells drilled with water-based drill-in fluid involved the alpha/beta wave-placement method. It was intended that the same method be used for the wells drilled with SOBM. As a result, significant fluid loss during gravel placement would not be tolerable. Indeed, previous attempts to drill with SOBM and gravel pack with aqueous carrier fluid in the manner envisaged for Alba have reported limited success,3* mainly because of problems caused by excessive fluid loss. Similarly, a development in west Africa involving drilling with oil followed by an aqueous, gelled, gravel carrier fluid reported losses on two of the three operations.4

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.

The penetration rates of dispersed and nondispersed water-base muds were studied using Mancos Shale. The full-scale wellbore simulator at Drilling Research Laboratory was utilized. Previous studies 1 have indicated that in invert oil muds higher penetration rates can be achieved when the weighting agent is ilmenite rather than barite. This study compares barite and ilmenite in water-base systems. Two grind sizes of ilmenite (fine and standard) were used in order to determine the effects of particle size on penetration rate.