Stimulation should always begin with a good understanding of the well history and the reservoir rock. This should include an evaluation of the formation composition and flow characteristics, permeability and porosity, and the mechanical properties of the rock. Determination of the "Key Factors" limiting stimulation success should be identified. The potential treatment fluids and technique should be evaluated for the ability to provide the necessary benefits to overcome these limits. This paper describes stimulation design and results in a carbonate gas field located in eastern Saudi Arabia. The field produces gas with H2S that varies from 0 to 10 vol%. The Khuff reservoirs, at 11,000 to 12,000 ft, are highly acid soluble carbonates (> 85 wt%) with elevated bottom hole temperatures approaching 275°F and a composition having increasing dolomitization with increasing depth. Acid leak-off control problems result from the presence of natural fractures in the formation. Various retarded acid systems were tested with reservoir rocks. In addition, the issues of corrosion control were considered given the low-carbon steel tubulars downhole (L-80 &C-95) and the H2S. Although the gas is sour, proper design of acid systems eliminates problems of iron sulfide and elemental sulfur precipitation. Evaluation of cored material showed 15 wt% anhydrite streaks. Kinetics studies conducted using reservoir rock indicated that the reaction rate of the in-situ gelled acid is an order of magnitude lower than that of neat acid. An acceptable corrosion rate on all metals by the acid in the presence of H2S and compatibility of all systems with reservoir fluids were obtained. Wells have been treated using acid fracturing techniques employing viscous fluids without encountering any operational problems. Substantial increases in gas production and flowing wellhead pressures have resulted from these treatments. Analysis of well flow back samples collected following acid fracture treatments was used to assess the effectiveness of the fracture treatments. Introduction Stimulation of carbonate reservoirs is typically the result of a need for restoration or enhancement of production to a more economic level. The design of these treatments requires a great deal of input to be successful. To begin with a thorough understanding of the reservoir is essential. This should include complete knowledge of the composition of both the mineralogy and the fluids, flow characteristics, permeability, porosity, and mechanical properties. After this is the need for a good knowledge of the well's history. Complete records of the drilling operations, production history, workovers, changes in wellbore parameters and the wellbore configuration. Lastly, as accurate a diagnosis of the damage or restriction inhibiting the economic production level. From all of this information will come the "Key's" to what to use and how to conduct the treatment. Certain wells by their nature add additional constraints or hurdles to overcome to reach the desired production increases. One of these is depth and therefore higher temperature and possible treating rate limitations. The higher temperature increases corrosion rate of well tubulars and limits depth of penetration due to increased reactivity, if acids are to be used as the treating fluids. Another well type, which adds additional concerns, is one that produces hydrogen sulfide (H2S) gas. The major effects on design are to deal with the potential of additional corrosion and the damaging reaction products possible from treating acids and the H2S. Recently, Saudi Aramco embarked on an extensive campaign to develop its gas fields. Acid fracturing has been used to enhance the performance of gas wells in a tight carbonate gas reservoir. In-situ gelled acids were extensively used in these treatments. These acids consist of a synthetic polymer, a crosslinker, and a breaker, and other acid additives. They cross-linker over a narrow pH range where their viscosity increase by several order of magnitude. The objectives of this work were to:evaluate in-situ gelled acids to stimulate deep carbonate gas reservoirs,assess the treatment in the field, andoptimize the treatment based on lab and field results.

In order to improve production and subsequent well economics in the Wolfcamp formation in Eddy County, New Mexico, horizontal drilling has been employed for the last seven years. Current stimulation practices in these horizontal wells involve hydraulically fracturing with proppant in multiple stages. The effectiveness of the various fracturing treatments on production responses is of interest, because any optimization or changes that can reduce stimulation costs improves profit. In addition, with the current shortages in all mesh sizes of sands, anything which reduces the quantities needed to effectively stimulate wells is a plus. Production from a localized group of horizontal Wolfcamp wells was examined to establish the impact scenario that proppant choice made on performance. It was found that decline rates were the same or better on wells fracture treated using a significantly lower volume of an Ultra-Lightweight proppant compared to those wells treated with regular sand. This reduction in proppant used also resulted in a savings ranging from 4% to 33% of the stimulation costs. Introduction The Wolfcamp formation in the study area of Eddy County, New Mexico, was deposited along a paleo shoreline and is a sequence of dolomite and shale layers above the producing interval with a sequence of limestone and shale layers below. Fig. 1 is an illustration of a typical openhole log. The major producing segment is the basal Abo, or Abo-Wolfcamp transition interval, which developed, as a fine-grained (re-crystallized) dolomite. When developed this fine grained characteristic, also known as sucrosic texture, is somewhat comparable to sandstone in terms of reservoir quality. Vertical wells in the area were first drilled in the 1970's with poor success. This lack of success was due to the formation being discontinuous horizontally and vertically limited; therefore making it difficult to hit the target with a vertical wellbore. Net Pay thickness is approximately 20 feet. Originally, the Bottomhole Reservoir Pressure was about 2000 psi. The Bottomhole Static Temperature is 105°F. Average porosity is 9% to 12% and average permeability <0.1 Millidarcy, with water saturations from 20% to 50%. Anticipated recoverable gas per well in the better part of the field is 2 BCF on 320 acres drainage. In 2001 to 2002 the first horizontal wells were drilled in the area with success. First stimulation attempts were made using hydrochloric acid given the carbonate lithology. This was somewhat successful however, propped fracture treatments proved to have a more significant effect on production. It has been determined from one of these wells in the study area that induced fractures have a 330 - 150 azimuth (NW to SE). This paper presents comparisons of propped fracture treatments utilized to achieve higher production capabilities. At the heart of this production improvement is the concept of a partial monolayer of proppant in the created hydraulic fracture 1–35. A partial monolayer is achieved at 0.06 to 0.09 pounds per square foot concentration of proppant over the fracture face. In this concentration range the optimum conductivity is observed for at most closure stresses. Included in this study will be the effectiveness of an Ultra-Lightweight proppant compared to traditional proppants. The Ultra-Lightweight proppant has been described before and evaluated in other studies 6–15. Of importance will be the effect on production decline of the different treatments and the differences in job costs.

Stimulation of carbonate oil and water producers with acid can result in an uneconomical increase in water production. This is the result of poor placement of the treatment stimulating the water-bearing rock preferentially to the oil. Typical treatments in the Nisku use selective tool isolation of zones to achieve the required placement control. The operational costs associated with this type of treatment make it difficult to perform economical stimulation treatments on marginal wells. Acid treatment of such a well, using only a diverting agent for control of placement, risks increased operational costs associated with possible increased water production and, therefore, the reduction of a marginal well to an uneconomical one. A unique diverting material formed by the reaction of an aqueous solution of dibasic acids and rosin esters, with divalent cations, present in formation water or spent acid allows the selective stimulation of only the oil-producing zones. The reaction product is an oil-soluble precipitant. The oil-soluble nature of the diverter base materials and the resultant precipitants makes the likelihood of the precipitant forming in the oil zones remote; however, in the event of such a result, the produced oil will remove the precipitant. Presented are laboratory tests describing the effectiveness of the oil-soluble material to divert acidic fluids away from water flows. Also, demonstrated is the subsequent cleanup of this oil-soluble diverting material using produced oil. In addition, several case histories from the Wayne area of Alberta, Canada are included. The results of these treatments demonstrate that control of acid placement in water-cut producers results in a considerable increase in oil production while minimizing the effect on water cuts. A significant reduction in the operational costs associated with switching from the selective tool isolation technique to the one described above is also demonstrated. Introduction Acidizing has long been accepted as a means of increasing production from oil and gas wells. A major problem with many wells is the increased production of water along with the hydrocarbons1,2. The scenario is even more accentuated if placement control is not used during the stimulation treatment. Placement control methods vary around the world2,3,4.These methods involve use of diverting materials5, foams6, mechanical isolation or the use of varying injection rate7. The production of water is an added cost to the operator in the form of disposal, treating and/or the possibility of scale formation in the wellbore. For example, a 6m3/day increase in water production is approximately equivalent to a $2.50/day ($ Canadian) increase in operational costs. A 180m3/day increase would mean a $75/day increase. Therefore, the extra revenue from an increase in oil production could potentially be offset by the increase in operational expense of the additional water. The water in the Wayne area is highly corrosive which, in turn, increases the cost of disposal. In Table 1, the costs are broken down into catagories, including chemicals to deal with the corrosivity. The primary difficulty with treatments that have had the least amount of success has been the inability to place the acid where it will do the most good. A correlation can be made between unsuccessful stimulation treatments (in terms of water inflow increases), and the inability to effectively place acid. This paper is focused on treatments that were conducted in the Nisku formation in south central Alberta (Figure 1).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractProduction of Hydrogen Sulfide (H 2 S) gas in oil and gas wells has increased over the last few years. These sour (H 2 S Producers) wells have been successfully acid stimulated for many years. Wellbore acid washes, high rate squeeze treatments and acid fracs have been the norm for stimulating wells in carbonate formations. However, to accomplish this there are many problems related to the interaction of the treatment fluids and the H 2 S. These can result in excessive corrosion, unwanted precipitants, metal cracking, etc.In recent years, the practice of drilling horizontal wells has led to the technique of underbalanced acid washing. Controlling corrosion, metal fatigue and unwanted precipitants when using this technique in sour formations presents a special challenge. The resulting interaction of the H 2 S and acid additives, especially corrosion inhibitors has been the primary focus of concern. This paper describes test equipment and procedures designed to investigate H 2 S and acid additive interactions. Test results with a range of inhibitors and additives designed to minimize formation damage and protect coiled tubing and tubular steels are provided. Specifically, weight loss, pitting and precipitation products are listed.

Partial or total lost circulation is prevalent in the Permian Basin of West Texas during many drilling and cementing operations. Whether losses are due to highly vugular or cavernous intervals or due to low fracture gradients, the problem occurs over the entire region. The common practices for fighting these losses are foamed mud sweeps, foamed cements, lost circulation pills and high-viscosity gel spacers containing lost circulation materials. This paper presents case histories representing more than 100 wells in which a new environmentally preferred system has been employed. Specifically, instances during drilling are discussed where partial to total losses in returns have occurred and have been restored by pumping 40 to 50 bbls of this new material. These same wells after restoring circulation resume drilling to total depth without any further losses. In addition, cases are presented where the system is used as a spacer pumped ahead of cement, resulting in the circulation of cement in an area where this has not occurred before. Another example resulted in the improvement of bonding by the cement. Additional scenarios demonstrate that pumping this material on a single stage cementing job, could replace the normal two stage job.