The objective of most acid stimulation treatments in Saudi Arabia’s Khuff carbonate formations is to remove drilling induced damage and achieve maximum well productivity. Open hole and multilateral completed wells, present several challenges that prevent an optimum intervention and placement of fluids with coiled tubing (CT). Traditional stimulation practices of these types of producers usually involve spotting fluid systems comprising multiple stages of pre-flushes, acid, and chemical diverting agents along the horizontal section of a well without adequate control over treating fluids’ placement and displacement. An innovative approach, combining fiber optic enabled coiled tubing (FOECT) and distributed temperature survey (DTS) recorded data with reservoir data to selectively place stimulation fluids in targeted formation sections, was successfully field tested in a dual-lateral horizontal gas well completed open hole in Saudi Arabia. This paper describes the job design, the operations performed to access the desired lateral, and the stimulation treatment performed combining the two technologies. Details on how the DTS technology was used to identify thief zones during the actual stimulation treatment, and how the placement of treatment fluids was optimized along the horizontal section, are also provided. The successful implementation of the first field trial has provided a strong incentive to utilize a similar approach in other gas producers currently scheduled.
The number of multilateral gas producers drilled in the Ghawar field has significantly increased over the past few years as part of the reservoir development strategy to maximize well productivity through maximum reservoir contact. Although these wells are expected to require little rigless intervention to conduct surveillance or productivity enhancement work, the effective options available to selectively access each of the laterals are limited. Thus specialized tools and techniques are required but the complex nature of these deep wells, combined with the high pressure and temperature characteristics of the reservoir, makes their application difficult and the outcome of the well intervention procedures uncertain. One of the techniques that has proven successful in different fields around the world, is the use of a lateral accessing tool to selectively access the desired lateral to then perform a stimulation treatment, run a production log, or any other operation. Combining lateral accessing and high-pressure jetting tools to access and stimulate two under-performing laterals a world first, was done in Well A, a producer drilled in a carbonate reservoir in Saudi Arabia's Ghawar field. The stimulation treatment was successful and the well achieved a two-fold rate increase. This paper provides details about the pre-job research and testing conducted, the methodology, equipment and procedure successfully applied in dual-lateral Well A, and lessons learned throughout the operation. The post-treatment performance of the well was better than anticipated, which encouraged Saudi Aramco to further utilize the technique for different applications. Introduction Although lateral accessing tools have been successfully used in wells around the world over the past few years, the gas producer selected for the first trial of this technique posed considerable challenges because of its casing size and the long length and heavy weight of the bottom-hole assembly, comprising the accessing and high jetting tools, that was run on coiled to access the lateral sections. Multilateral candidates provide options to increase the productivity of gas fields during their productive lives, using an effective stimulation treatment. This was the first successful attempt to access each lateral in a multilateral well. Previous unsuccessful attempts resulted in having to bullhead stimulation treatments in wells with a similar configuration, with relatively poor results.
H.A. Nasr-El-Din, SPE, G.E. Bitar, SPE, F.I. Bou-Khamsin, A.K. Al-Mulhim, SPE and J. Hsu, SPE, Saudi Arabian Oil company (Saudi Aramco) Abstract High water production causes major economic and operational problems for several reasons. It decreases oil production, and results in large amounts of produced water that need to be disposed. It also requires increased capacity of water separation and handling facilities. Other production related problems include high corrosion rates and increased tendency for emulsion and scale formation. Therefore, there is a need to reduce water production. Several mechanical and chemical methods are available for water shut-off treatment. However, the choice of a specific treatment depends on the source of water, well characteristics, and cost. Water shutoff treatments using chemical means include injection of a gelling solution that forms a gel at reservoir conditions. Three main gelling systems are available to conduct water shutoff treatments: a water-soluble polymer with a cross-linker, phenol-formaldehyde resin, and sodium silicate gels. Based on extensive lab studies, two gelling systems were field tested in Saudi Arabia during the last few years. Both gelling systems were applied in a carbonate reservoir. The reservoir temperature is 220-240 F and formation water has total dissolved solids ranging from 45,000 to 200,000 mg/l. The first gelling system consisted of a polyacrylamide polymer, acetate and a retarder. This system was applied in two wells as a means to reduce water production due to coning and bottom water. The second gelling system consisted of sodium silicate with intemal and extemal activators. This system was applied in a well with a high permeability streak. Several operational and quality control problems were encountered during and after field applications. This paper discusses these problems in detail and recommends modifications to these systems to avoid operational problems encountered in the field. Advantages and disadvantages of using several gelling systems are also highlighted. P. 133
Tight emulsions, formed during the production of Arabian Light crude oil, were causing problems at an increasing number of wet crude handling facilities. The processing of these fluids impacted operations in three major areas: Inability to produce some wells, particularly during cooler weather. Plant upsets due to grid trips and accumulation of sludge in vessels. Increased demulsifier usage. The overall effect was a loss of revenue and increase in treatment costs. In January 1995 a multi-disciplined team of scientists and engineers was formed to characterize the emulsions and make recommendations for improved emulsion treatment. Studies showed that solids, which include scale particles, are precipitated from produced fluids during production. These solids were shown to be largely responsible for the formation of stable emulsions in our systems. A very successful scale squeeze program was already in place to mitigate carbonate scaling - with squeeze lifetimes of over ten years. Based on the link between scale and tight emulsions, this program was accelerated and scale treatments were performed on emulsion ‘problem’ wells to suppress solids formation and therefore reduce/ eliminate emulsion problems. The paper describes the emulsion model developed. The mechanism of organic and inorganic solids precipitation during production is presented and the effect of pressure drops caused by mechanical ‘chokes’ used for well restriction is demonstrated. Scale inhibitor squeeze and encapsulated inhibitor treatments are discussed with reference to case histories. The effectiveness of scale inhibitor in reducing emulsion tightness is demonstrated using laboratory data. The paper concludes by summarizing the success of this treatment strategy in terms of economics, reduction of chemical demulsifier use and elimination of downtime due to emulsion problems
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