TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractEffective matrix acidizing of horizontal and multi-lateral wells is a very difficult task. Unlike vertical wells, horizontal wells can extend several thousands feet in the formation.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDrilling horizontal wells with extended reach is intended to maximize reservoir drainage and minimize water production due to water coning. However, an inherent problem with these wells is poor acid distribution during matrix acidizing, especially in reservoirs with high permeability streaks. This paper discusses an innovative approach to treat horizontal wells with extended reach. This new technique comprises mechanical diversion in the wellbore, and chemical diversion in carbonate formations.Coiled tubing has been used for years to better distribute the acid in vertical and horizontal wells. However, application of coiled tubing in long horizontal wells is a function of wellbore diameter and length. Coiled tubing cannot reach the total depth of the well if there is large washout, or if the length of the openhole is greater than what the CT can reach. The maximum length that CT can reach depends on the length of the reel, diameter of the coil and wellbore geometry. To extend this length, we have used a hydraulic tractor to pull the coiled tubing to the total depth of the well. This will ensure better acid distribution over the wellbore. To enhance acid diversion in the formation, a visco-elastic surfactant-based acid system was employed.Wells selected are horizontal that were drilled in a carbonate reservoir in the oil fields (both land and offshore) that are present in the eastern part of Saudi Arabia. The total length of the target zone for the well "A" and well "B" is 13,543 and 20,304 ft, respectively. Typical coiled tubing (1 ¾-inch) cannot reach the total depth in these wells (CT lockup length is 10,300 ft for well "A" and 13,200 ft for well "B").A special hydraulic tractor was used to pull the coiled tubing to the total depth of these two wells. A visco-elastic surfactant based-acid system was utilized to remove formation damage induced by the drilling fluid (water-based mud) and enhance the permeability of the formation in the critical wellbore area. Corrosion inhibitor and other acid additives were carefully selected to maintain the integrity of well tubulars, coiled tubing and the tractor (metallic parts, O-rings and seals of the tractor). Before attempting the stimulation of the extended reach well, a water jetting method was adopted to remove near well bore damage resulting from the drilling mud cake and mud invasion. Production logging tests were conducted after drilling the well, after the water jetting treatment, and after the matrix stimulation. The productivity index of the well decreased after the water jetting treatment. However, the acid matrix treatment delivered through the CTtractor nearly doubled the productivity index of the treated well.

Effective matrix acidizing of horizontal and multilateral wells can be a highly challenging task. Unlike vertical wells, horizontal wells can extend several thousand feet into the formation. Reservoir heterogeneity and the length of the horizontal leg can make acid placement and diversion very difficult. In addition, the low drawdown encountered in horizontal wells results in longer times to lift the spent acid from the well, especially in tight formations.To achieve better acid diversion in horizontal wells drilled in carbonate reservoirs, a viscoelastic-surfactant-based system was used. The components of this new system are HCl and a viscoelastic surfactant. The acid dissolves calcite and dolomite minerals and produces calcium and magnesium chlorides. The increase in pH forces the surfactant molecules to form rod-shaped micelles. The produced chloride salts further stabilize these structures, especially at high temperatures. The rod-shaped micelles will significantly increase the viscosity of the acid, diverting the acid into tight, unstimulated, or severely damaged zones.More than 100 wells with openhole (OH) completions were successfully stimulated in two offshore oil fields in Saudi Arabia by use of the new acid system. With a water zone 30 ft away from these OH sections in one of the fields, growth of any dominant wormhole into these sections could increase water production. The wells that used the new treating fluid produced an average of 1,600 BOPD more than conventionally treated wells, with no indication of water production. Field results [pre-and post-oil and -water production rates and flowing wellhead pressure (FWHP)] demonstrate the effectiveness of the new acid system to matrix acidize long horizontal wells with OH completions. The simplicity of the system makes it the fluid of choice, especially in offshore and sour environments. The absence of metallic crosslinkers in this system eliminates problems associated with sulfide precipitation in sour wells.

fax 01-972-952-9435. AbstractA new development strategy used by Saudi Aramco for carbonate reservoirs is to drill multilateral, extended reach, horizontal and fishbone wells. This strategy has a significant impact on reducing the development cost per bbl of oil produced, by drilling less wells and requiring less offshore platforms. This is also applied for the development of carbonate reservoirs in highly populated areas.Drilling multilateral wells is intended to maximize reservoir drainage and minimize water production due to water coning. However, inherent problems with these wells are poor accessibility and uneven acid distribution during matrix acidizing, especially in reservoirs with high permeability streaks. This paper discusses an innovative approach to treat multilateral wells. This technique comprises mechanical diversion in the wellbore and chemical diversion in the formation.In the past, reentry access to sidetracks from an open hole main wellbore was not possible. This prevented remedial operations on individual laterals and precluded effective reservoir management. To selectively enter and stimulate the desired lateral, a coiled tubing conveyed orienting tool was used. This ensured better acid distribution over the wellbore. To enhance acid diversion in the formation, a viscoelastic surfactant-based acid system was employed.Well "A" is an offshore dual open hole multilateral horizontal well with a motherbore length of 2,256 ft and a lateral section of 3,558 ft. The lateral was rotary jetted with acidic brine during the completion phase, but the well did not sustain flow after a nitrogen gas lift.A special CT conveyed multilateral tool was successfully used to enter the lateral. A viscoelastic surfactant-based acid was utilized to remove formation damage induced by drilling fluids, and to enhance the permeability of the formation in the critical wellbore area.The well responded to the acid treatment and its production exceeded expectations. Challenges, design criteria, field treatment and evaluation, lessons learned, and recommendations are discussed in this paper.

Calcium carbonate scale represents a significant safety and operational problem in offshore carbonate fields operated by Saudi Aramco. Scale can form on any surface where the pressure drop is sufficient for the produced fluids to form the scale and unload entrained solids. These solids will deposit on wellhead equipment such as the wellhead surface valves, piping, well tubulars and may plug the perforations. Well safety is jeopardized by hindering the operation of critical safety valves such as subsurface safety valves (SSSVs) and surface safety valves (SSVs). Further, scale buildup can cause backpressure problems in the tubing as the pipe internal diameter is reduced. Identification of scale in impacted wells requires periodic inspection and repair. This paper presents Saudi Aramco's experience in eliminating calcium carbonate scale by treating existing scale using HCl acid. Scale mitigation was initially attempted using an encapsulated inhibitor placed in the rat hole of vertical wells. This method had a limited treatment effective life and Saudi Aramco has moved to using inhibitor squeeze treatments. Chemical squeezes places inhibitor (phosphonate-based) directly into the formation of wet oil producers and is now the currently employed method of long-term prevention of scale. Case studies using both methods of scale mitigation are discussed as well as future plans to improve the effectiveness of these treatments. Introduction Field "B" is located both onshore and offshore along the western edge of the Arabian Gulf. The field is a north to south trending, elongated, anticlinal structure which measures 40 Km in length and 19 Km in width. This field was discovered in June 1964 and oil production began in 1967. Field "B" is a multi-reservoir field with 11 oil-bearing reservoirs at various depths from 2,133 to 3,048 meters (7,000 to 10,000 ft). The crude grade is Arab Extra Light crude with 7.5 mol% H2S and 4.5 mol% CO2. The two main reservoirs in this field are the HN and HD. The main productive formations have a low permeability in the range of 1–50 mD. The HN and HD reservoirs are carbonates reservoirs. Bulk XRD analysis of the HN reservoir cores indicates that the zone of interest contains 97–100 wt% calcite and 0–3 wt% ankerite. On the other hand, HD reservoir cores contain 70–92 wt% calcite, 0–30 wt% dolomite and 0–5 wt% ankerite.1 For pressure support purposes, peripheral water injection began in 1973 using 14 injectors into the HN reservoir and 28 injectors into the HD reservoir. The injection water is drawn from a shallow aquifer. The produced water is injected into a separate, segregated disposal system. Water breakthrough first occurred in the HN reservoir in mid 1975 and in late 1978 in the HD reservoir. Water-handling facilities were placed in service in 1983. The water cut for both the HN and HD reservoirs has gradually increased since the commissioning of these facilities and currently the field produces crude oil with an average water-cut of 32 vol%. The first scale build-up problem was encountered in 1987. Since then, scale became a difficult problem to manage as more wells started to produce formation or injection water. Scale build-up has resulted in several operational problems and production losses. The main objectives of this study are to:give a brief summary on the scale problems encountered in Field "B" carbonate reservoirs,discuss how this problem was addressed, andsummarize field experience gained from solving this problem. Chemical Analysis of the Formation Brines The composition of the produced water varies significantly for the HN and HD reservoirs as noted in Table 1. The Total Dissolved Solids (TDS) for the HN reservoir brines varies from 27,000 to 230,000 mg/L. The calcium ion concentration is in the range of 1,904–18,876 mg/L. The TDS for the HD reservoir brines is higher than that of the HN brines and varies from 33,400 to 292,000 mg/L. Calcium ion concentration is in the range of 2,392 to 39,280 mg/L.