Summary This paper reports the first results of stress-oriented and aligned perforating of deviated wells at the Kuparuk River field, Alaska. Preferred perforation alignment and Preferred perforation alignment and spacing are calculated for each well so the fractures from individual perforations link to produce a single perforations link to produce a single "zipper" fracture plane along the deviated wellbore. Results of the first application of this technique are presented from the 26-well development presented from the 26-well development of Drillsite 2K. The results from use of three different oriented casinggun systems and pertinent data from Drillsite 2K fracture stimulation treatments are discussed. Comparisons to drillsites where nonaligned perforating strategies were used show a perforating strategies were used show a significant reduction in perforation friction, enabling the placement of larger, more productive fracture treatments. Application of this technique to deviated and vertical wells and its use at Kuparuk on developments after Drillsite 2K are discussed. Introduction Perforation design for a well that will be Perforation design for a well that will be hydraulically fractured is usually controlled by the requirements to place the stimulation treatment. Key parameters are the number, size, orientation, and phasing of perforations. Typically, the objective is either perforations. Typically, the objective is either to minimize or, in the case of limited entry treatments, to control the amount of perforation friction during the stimulation perforation friction during the stimulation treatmeat. No uniform criteria exist within the industry for defining perforation phasing or shot density. Different operators use different techniques. However, the pumping of a fluid stage to break down the well and to calculate the perforation friction loss is routine to verify that sufficient communication exists between the wellbore and the formation to place the fracture treatment. Often, a ballout treatment is pumped before the main stimulation to force additional perforations to breakdown. Although it is perforations to breakdown. Although it is generally acknowledged that the optimal placemeat of perforations in a vertical well is placemeat of perforations in a vertical well is 180 phasing in the fracture plane, which is perpendicular to the far-field minimum stress, there are, to the best of our knowledge, no reported efforts of routinely practicing such a technique. Laboratory practicing such a technique. Laboratory investigations into fracture initiation from deviated wells showed the importance of perforation placement on the length of perforation placement on the length of wellbore intersecting the fracture. During the past 7 years, more than 600 new development wells have been fracture -stimulated in the Kuparuk River field. The large number of treatments has provided the opportunity for significant advances in the technical and operational aspects of hydraulically fracturing deviated wells that are not aligned colinear to a direction of principal stress. The success of this stimulation principal stress. The success of this stimulation program was documented in Refs. 4 and 5. program was documented in Refs. 4 and 5. Perforation strategy during the initial development consisted primarily of perforating the net pay intervals in the Kuparuk A sand. Depending on the drillsite, this would result in the perforating of two or three separate zones. Before the wellbore tubulars and completion equipment were run, casing guns (4 1/2-in.) were shot with a typical shot density of 4 shots/ft and a phasing of either 90 or 120. We often used largehole shots every fifth hole. Most initial fracture treatments pumped in wells where this strategy was used had relatively high perforation friction drops ranging from 500 to perforation friction drops ranging from 500 to 1,500 psi. Post-treatment temperature and tracer logging often showed fluid entry into a few discreet points along the perforated interval, with the lowest zone of the A sand often showing no evidence of fracture stimulation. The poor communication at the wellbore is thought to have caused many treatment screenouts in the field.

Sixty-five percent of the reserves of the Kuparuk River field, the second-largest producing oil field in the U.S., is contained in a 20-to 80-md-permeability sandstone. This paper provides details of stimulation design advances made over the past 3 years in this formation. The design steps for optimizing fracture treatments in a moderate-permeability formation require primary emphasis on fracture conductivity rather than on treatment size or fracture length. This philosophy was used for the 140 new wells documented in this paper. Treatment size was gradually increased once a commensurate increase in fracture conductivity was obtained. Applying the new design to the refracturing of 88 producing wells in the field resulted in an incremental 40,000 BOPD, a significant portion of the field's 300,000 BOPD.

The vast number of wells and unique operating conditions in Alaska's Prudhoe Bay field have presented many opportunities for those involved in remedial wellwork. Among the technologies that have either been pioneered, tested, or applied there, coiled tubing (CT) ranks as one of the most long lasting and widely used. This paper highlights the more recent applications of CT in the field. The paper begins with a brief overview of the Prudhoe Bay Unit's (PBU) CT wellwork program and then follows with discussions on eight CT applications that have been developed or expanded in the last two years. Some are new technology and others are old techniques with a new design. Descriptions and procedures ate given for each in addition to performance results thus far. Introduction The Prudhoe Bay Field contains approximately 1,200 wells which produce over 900,000 barrels of oil per day. Along with this large oil rate, 1.2 million barrels of water and 7.5 billion cubic feet of gas are produced each day. As water processing costs are very high and gas is currently not marketed from the North Slope, the search for reliable water and gas shut-off techniques is never ending. In the continual effort to optimize oil production, PBU wellwork has become a major program. Many tools and technologies have been used over the years in the program, but CT has risen to be one of the most significant pieces of it because of its versatility, capabilities, and cost effectiveness. Typical CT remedial operations cost 5% to 15% of conventional rig options. The large wellwork program and its diverse challenges have provided countless opportunities for CT technology. Many of these advancements have been presented in past papers. As the field ages, wellwork becomes more and more challenging which requires continual improvement in technology to keep pace. This paper highlights the most recent advancements and applications of CT in remedial work. CT Wellwork Program The CT program on the North Slope has grown to be one of the largest in the world. Between the two operators of the nine fields there, 8 coiled tubing units (CTU) are contracted to run on a near daily basis. Two service companies maintain and operate these units and provide critical expertise. In PBU alone, over 1000 CTU operating days are spent on some 600 wellwork jobs striving to keep wells operating efficiently and oil production at a maximum. Applications. There are many applications of CT in the wellwork program at PBU. They range from simple nitrogen lifts to complex remedial completions. Below are the major categories of applications and many of the associated jobs performed. Reservoir Surveillance - Memory surveys and CT electric line logs of all types Capacity Sustainment - Stimulations, perforating, fill clean-outs, nitrogen lifts. Gas & Water Shut-offs - Cement and chemical squeezes, mechanical and inflatable plugs, mechanical straddles. Injection Control - Profile modifications with cement, chemicals, and mechanical devices. Mechanical Repairs - Tubing patches & straddles, cement packer repairs, liner repairs, etc. Miscellaneous - Fishing, ECP's, velocity strings, etc. Prior to the technological advancements of CT, many of these jobs could not have been performed in certain wells or would have been left for a rig workover (RWO). Now, these jobs are often routine events due to the ever expanding use of CT. Technologies. With the variety of CT wellwork being performed naturally comes a variety of associated technologies. Some of the more prominent ones that are advancing the applications of CT are: P. 47

The new diagnostic plots technique is proposed to evaluate four key gel gas shut-off treatments conducted at Prudhoe Bay last year. The diagnostic plots determined that a permeability contrast or formation channeling was the main mechanism for large gas entries. A log-log plot of Gas/Oil ratio versus time exhibited the characteristic behavior of initial gas coning and quickly turned into a rapid formation channeling problem. The excess or free gas production during the coning to channeling evolution could be used to deduce a proper gel treatment volume. Post treatment well production data were plotted and compared with the pre-treatment diagnostic plots. Changes in the slope or trend of Gas/Oil ratio curves were used as an indicator of a successful gas shut-off treatment. The technique will require further confirmation as more gel gas shut-off treatments are performed. Introduction The thick Prudhoe Bay Sadlerochit sandstone formation, which is at a vertical depth of 8,800 ft, is bounded by a gas cap and a bottom water aquifer. Portions of the field have been under waterflood since 1980. The field is producing approximately 0.9 MM BPD oil, 1.5 MM BPD water and 7 MMM SCFPD gas. As reservoir depletion continues, water and gas production rates continue to increase. Most of the produced water and gas are re-injected. The majority of gas is re-injected into the gas cap. Some is made into miscible injectant for a tertiary recovery process. The water is treated and filtered and incorporated into the ongoing waterflood program. However, the capabilities of water and gas handling surface facilities are limited even after recently completing a series of plant expansion projects. Increasing water and gas production drives up water and gas handling costs and decreases oil production. As reservoir depletion continues, gas cap and enriched gas as well as waterflood water breakthrough occurs frequently at the producing wells. The Gas/Oil and Water/Oil contacts get closer and closer to the perforated intervals. The potential of bottom water and gas cap gas coning and channeling increases. The gas and water produced by these adverse mechanisms by-pass reserves and impede normal production. It is critical to develop an engineering approach for identifying and treating the excessive or free gas and water production wells. This entails first determining the gas/water inflow mechanisms and locating their entries at the wellbore. Then a viable but cost effective gel placement technique can be developed. Finally, a coherent production and reservoir engineering evaluation method for determining the treatment technical and financial success can be undertaken. The Diagnostic Plots New diagnostic plots have been developed to differentiate between mechanisms of excess water and gas production. The production data are used to plot in log-log the WOR, GOR or WOR (Water/Oil, Gas/Oil and Water/Gas Ratios respectively) and their derivatives versus time. Together with the completion and workover history, the excess water and gas production mechanism can be determined. P. 421

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractGel-Cement Combination Squeezes have been successfully used for gas shutoff applications. Coupled with coiled tubing selective placement, gels and cements exhibit a synergistic gas shutoff effect. Gels provide an indepth block to gas production by forming a crosslinked polymer network within the porous media. Cements are able to fill voids and cavities to block gas production and provide a strong near wellbore block. Thirteen treatments have been performed to date with an economic success rate of 85%. Implementation of the technology required the use of a well-controlled gel system, consideration of possible contamination issues and modification of current coiled tubing placement strategies.