Mechanical descaling of iron sulfide scales in high angle non-monobore or horizontal open hole completion offer multifaceted challenges, especially when the reservoir is depleted. The history of the descaling program in carbonate gas wells in Saudi Arabia dates back to 2007. The program suffered several setbacks with operational complexities like stuck pipe, H2S generation (souring) during chemical dissolution and severe induced damage during reservoir isolation process. The depleted reservoir needs to be isolated to ensure full circulation during mechanical descaling process. The mechanical means of isolation with a bridge plug is not feasible due to the presence of FeS scale in the wellbore. The only isolation option available at the moment is CaCO3 chips bullheaded from the surface. Often the post-descaling and stimulation operation does not restore the original production, due to the heavy damage induced in the reservoir during isolation. This paper shares a successful descaling experience and best practices in a single lateral open hole well that was completed with 4-1/2-in tubing and 7-in liner, and had severe pressure depletion. A novel non-damaging visco-elastic surfactant based fluid was used to fill the open hole lateral and as base to support CaCO3 chips above it that prevented additional damage and allowed reservoir isolation for mechanical descaling, using high pressure coiled tubing and a jetting tool. A clean wellbore with no further induced damage made subsequent post-stimulation results very attractive. The paper also presents the production results of stimulation treatment performed after the descaling treatment.

During the last 5 years, one of the most common matrix acidizing enhancement techniques used to improve zonal coverage in open hole or cased hole wells is conducting a distributed temperature survey (DTS) using coiled tubing (CT) equipped with fiber-optic and real-time downhole sensors during the preflush stage before the main stimulation treatment. This is used to identify high and low intake zones so the pumping schedule can be modified to selectively place diverters and acidizing fluids with a high degree of control. Once stimulation treatment has been completed, a final DTS analysis is performed to evaluate the zonal coverage and effectiveness of the diversion. Even though this technique has provided satisfactory results, alternative methods providing faster and more accurate understanding of flow distribution between the zones and laterals are needed, especially if there is limited temperature contrast between fluids and reservoir. Thus, an innovative coiled tubing real-time flow tool has been recently developed to monitor flow direction and fluid velocity. This measurement is based on direct measurement of the heat transfer from the sensors to the surrounding fluid using a calorimetric anemometry principle. The first worldwide use of this technology in a Saudi Aramco injector well showed this to be a viable new approach to downhole flow monitoring that can be used by itself or in conjunction with DTS, depending on the constraints of each individual intervention.

In the Bay of Campeche, Mexico Marine operators have recently commenced the development of their high pressure, high temperature (HPHT) oil and gas fields in order to meet the high demand. These new developments present tough conditions for all aspects of well drilling and completion activities. They are particularly challenging for performing well intervention, which have driven operators, manufacturing and service companies to develop innovative strategies for servicing these fields. For HPHT well developments, electric line conveyed guns is the most common technique employed to perforate wells in the area, whether dynamic or static conditions. Nevertheless, coiled tubing (CT) deployed perforating has been recently employed as a reliable option in the following cases:Electric line is not a technically suitable option due to the limited magnitude of under-balance at which it can safely operate.Drag and buoyancy forces encountered in the wellbore are close to the operational limits of the cable.Wellbore tortuosity, tubular restrictions and well configuration render electric line unable to access perforation target depth. Initially, this paper discusses the workflow for performing technical analysis to develop safe and economical CT conveyed perforating operations for HPHT wells in offshore Mexico, which considers CT string design, surface equipment, well control equipment and associated downhole tools. It then presents case histories and lessons learned. And finally, provides conclusions and recommendations from the experiences gained for performing HPHT CT deployed perforating activities in Mexico Marine. Introduction HPHT define well conditions above what is considered normal levels of pressure and temperature. For Mexico Marine operators any well intervention with wellhead pressure (WHP) above 3,500 psi and bottomhole temperature over 150 oC (BHT) is considered HPHT. The Bay of Campeche is located at the southeast of Mexico in the continental platform of the Gulf of Mexico in front of Tabasco, Campeche and Yucatan coasts (Fig. 1). In 2004 Mexico Marine operators started to develop in the Bay of Campeche a significant number of fields that meet HPHT definition. In Mexico Marine HPHT fields, electric line conveyed gun is the most common technique employed to perforate wells. However, CT conveyed perforating has been recently proved as an excellent option in cases where electric line restricts under-balance magnitude for safe operation, drag and buoyancy forces encountered in the wellbore are close to the operational limits of the cable, and tubular restrictions and well configurations may be a concern to access perforation target depth. Mexico Marine HPHT Environment HPHT developments (Fig. 2) in the Bay of Campeche target Cretaceous (K) and Upper Jurassic Kimmeridgian (UJK) formations. Cretaceous is a naturally fractured carbonate formation ranging depths from 4,500 to 5,500 m with Porosity ranges from 3.0 to 5.0% and Permeability of 18 md. Upper Jurassic Kimmeridgian is a dolomitized carbonate formation in Oolitic banks from 5,000 to 6,000 m, where Porosity ranges 5.0 to 8.0% with Permeability from 20 to 40 md. The new fields under development are highly pressurized with bottomhole pressure (BHP) from 10,000 to 12,000 psi and BHT up to 190 oC. In surface, shut-in pressures from 6,000 to 8,500 psi have been recorded, and hydrocarbon production is composed by gas and oil from 27.0 to 48.0 oAPI. Drilling operations are performed by jackup rigs from eight-leg fixed platforms in water depths up to 60 m. Well deviation ranges 0 to 60 o, and jackup rigs are also the most common structures available for well completion and workover operations. These rigs have a limited crane capacity of 30 ton to lift and position CT string onboard.

Many oilfields in southern Mexico produce from naturally fractured carbonate reservoirs with a high water cut. The majority of the remaining reserves are in the formation matrix. The objective when stimulating these wells is to connect the formation matrix with existing fractures. However, in some cases, the water-oil contact is close to the producing interval and the salinity of the water is more than 350,000 ppm. This results in rapid scaling and loss of production. The time for the scale to plug the well is a function of the volume of water produced.The challenge in these wells is not only to selectively divert the treating fluid away from the natural fissures/fractures-thief zones-invaded with water, but also to reduce water production from the natural fractures and fissures after the treatment. To treat the formation matrix, the diverter fluid must reduce the high permeability of the water-saturated intervals without impairing the permeability of the oil-producing intervals.Historically, in southern Mexico, viscoelastic surfactants have been used as main diverter for acidizing treatments. However, these systems have been successfully implemented in other applications. The surfactant also acts as a disproportionate permeability modifier (DPM) as the water cut is reduced after the treatments. The water cut of wells stimulated with treatments including the surfactant-based diverter remains below 10%, and the wells typically produce over 1,000 BOPD for more than 200 days before the scale has to be removed. The water cut of wells treated conventionally in the same field is typically above 60%, and the wells produce for fewer than 50 days after being treated before plugging with scale. The ability of the solids-free surfactant-based diverter to limit water production has made possible developing a field that previously was considered uneconomic due to the saline precipitation into the formation. Overview of ScalingScaling can be a serious problem for the oil and gas industry (Zhang et al, 2015). Scaling is the deposition of a mineral salt on processing equipment, and it is considered a result of supersaturation of mineral ions in the process fluid. This supersaturation of ions is caused by several factors (Nergaard and Grimholt 2010).

Treating deep hot carbonate reservoirs, such as those found in the Arabian Gulf, presents a series of complex and related challenges to achieve effective and uniform stimulation. Due to the elevated temperature and heterogeneous formation, achieving good reservoir contact with an acid system along the entire interval of interest requires robust treatment fluids that can withstand the harsh environment. Recently, a novel single-phase retarded acid (SPRA) system and an engineered degradable large-sized particulate and fiber-laden diverter (LPFD) were introduced in a well in the Arabian Gulf, yielding strong results for the stimulation treatment. The SPRA, a 15% HCl-based acid system, showed excellent performance in a high-temperature environment (320°F). The fluid delivered similar friction pressures to unmodified 15% HCl, wormholing performance equivalent to emulsified acid without encountering the issues of fluid quality with respect to emulsion stability, and much higher dissolution power than organic acids and chelating agents. The pressure drop after the first acid stage was over 1,000 psi in about 60 min. After the second stage of acid, the pressure drop was close to 1,000 psi in about 30 min. Previous stimulation jobs in the region indicated a need for a significant amount of traditional diversion materials to achieve an effective plugging of the leakoff zones. A novel degradable LPFD system was introduced, achieving a significant increase of injection pressure (~1,000 psi) across the perforations. In addition to the effect on the diversion pressure, the implementation of the LPFD system has helped to reduce the footprint in offshore operations, has simplified materials handling, and has delivered the most efficient diversion performance in bullhead operations compared to other diverters. This article presents a novel method of stimulating deep hot offshore wells by combining an efficient SPRA and a unique degradable LPFD. These methods represent a step change to current practices and can be considered for effective stimulation in challenging carbonate formations.