Since the advent of horizontal technology, new wells have been drilled with thousands of feet of horizontal section to expose large reservoir areas. The advancement of drilling technology also allows drilling more complex wells, such as multilaterals for maximum reservoir contact (MRC). These complex wells impose great challenges with respect to well accessibility for rigless well interventions. One of the initial well interventions, which follow drilling completion, is acid stimulation to remove formation damage. On the other hand, the recent advancement of coiled tubing (CT) enables rigless interventions of complex wells while acquiring real time downhole measurements. The fiber optic enabled coiled tubing (FOCT) provides combined services of data acquiring and running other CT tools required for well treatments. The fiber optic telemetry system consists of a pump-through bottom-hole assembly (BHA) with a casing collar locator (CCL), pressure and temperature sensors, optical fibers inside CT, and a surface readout unit. By the virtue of the optical fiber, distributed measurements are also viable options to obtain temperature profiles. The temperature surveys allow evaluating flow distribution through temperature responses, thereby optimizing acid stimulation. A multilateral tool (MLT) using an indexing flow activated bent sub allows locating and accessing the laterals and stimulating them. The CCL readings via the FOCT provide a real time confirmation of accessing laterals. This paper highlights the first worldwide CT application of combining the fiber optic telemetry system for acquiring downhole data on real time, and a multilateral tool for accessing and stimulating a trilateral oil producer in a major carbonate reservoir in Saudi Arabia. This combination has resulted in a successful optimized acid stimulation of all three laterals. This paper also discusses in detail the job execution challenges, lessons learned, and experience gained to optimize similar future jobs. Introduction Drilling horizontal wells become the more commonplace in many Saudi Aramco fields. Recent advances in drilling and completion practices enable us to drill more complex wells with various types and shapes, such as extended reach wells, bilateral, multilaterals, maximum reservoir contact (MRC), etc. Benefits of drilling these wells include reduction in development and operating cost because of the lower number of wells and improve the reservoir performance and management. These complex wells are drilled for various reasons and many objectives, which may include but not be limited to: increase production, enhance reservoir characterization, improve sweep, maximize recovery, and ensure efficient reservoir management1, 2.

Water control is the key to prolong well life for economical and efficient oil recovery. When water reaches certain levels, oil production profitability decreases dramatically and even goes to negative. One feasible option in this case is a rigless water shut-off treatment, which involves an intensive process, starting from candidate selection and finishing with post-treatment well performance analysis. This kind of operation becomes more challenging for horizontal wells with open hole completion. Well A, a horizontal open hole producer with 2,440 ft of reservoir contact, was drilled and completed in November 2000. The last well production profile was determined by a Flow Scan Image (FSI) log, which showed 51% of water cut and the entry of most of the water was from the toe of the horizontal section. Based on economical and technical feasibility, fiber optic telemetry enabled coiled tubing (CT) was selected for an accurate and effective way to isolate the water producing interval, reduce water cut and enhance oil production. The advanced and intelligent CT enables real time downhole measurements via fiber optic telemetry system. The system consists of surface readouts including dynamic interpretation software, fiber optic cable, and bottom-hole sensors, which provides Casing Collar Locator (CCL) readings, Distributed Temperature Survey (DTS), temperature, internal and external CT pressure measurements. Permanent zonal isolation, utilizing an inflatable packer with a cement plug above the packer, was successfully performed using CT conveyed fiber optic system. The availability of CCL, temperature and differential pressure readings enabled precise depth control, proper packer inflation and optimization of the cement design. This paper highlights the application of a CT equipped with fiber optic advanced technology on a rigless water shut-off job. The paper also discusses the water shut-off (WSO) job design and execution challenges. Introduction Drilling horizontal wells become the norm in many Saudi Aramco fields. As horizontal wells mature, oil rate is reduced due to increasing water production, which dictates the need to perform water shut-off jobs to sustain oil production.

An alternative scale inhibition method using encapsulated scale inhibitor has been successfully used to control calcium carbonate scaling in the Ghawar Field oil wells of Saudi Aramco, Saudi Arabia. Field tests indicate that the Ghawar Field requires a low threshold scale inhibitor concentration for scale mitigation. The encapsulated phosphonate scale inhibitor treatment procedure is thus ideally suitable for scale control in such fields. Since 1994, a total of 89 wells have been treated with this procedure. After more than five years of treatment, there has been no reappearance of scale deposit on the treated wells except for two instances of scaling. Low treatment cost and the resulting long treatment life have provided an excellent incentive to treat more wet producers using the encapsulated scale inhibitor treatment method instead of treatment by conventional scale inhibitor squeezes. An additional benefit is realized from this encapsulated inhibitor method when treating marginal high water cut wells and wells located in low pressure areas by ensuring that the wells sustain flow after the treatments without the need for extensive livening work. This paper presents the results of a field case study where calcium carbonate scaling was controlled using the encapsulated scale inhibitor treatment procedure. Treatment design, job procedure, inhibitor return monitoring, economic analysis and comparison with conventional squeeze treatments as well as future applications are presented. Introduction Calcium carbonate is the most commonly encountered scale in the Ghawar Field of Saudi Arabia. Due to the presence of high reservoir pressure (>2700 psi) with reservoir fluid containing 5–20% dissolved acidic gases (CO2 and H2S), there is no CaCO3 scaling problem in the reservoir and at the bottom-hole of the tubing. However, as the fluid moves up the production tubing, the dissolved gases flash out of the brine as pressure is reduced. The loss of CO2 results in an increase in fluid pH. This shifts the thermodynamic balance, and results in the brine being supersaturated with respect to CaCO3. By the time the nucleation and kinetics of crystal growth favor the scale formation, the brine has reached the top 1000 feet and higher of the production tubing. The CaCO3 scale formation is represented by the equation: Calcium carbonate scale formation has resulted in production loss and severe field operational problems in the Ghawar Field oil producers. Since 1987, conventional scale inhibitor squeeze treatments have been used to control this scaling problem. All wet producers in the Ghawar Field require scale inhibitor treatments to avoid production loss as well as expensive scale removal from the producing tubing string, wellhead, manifold and flow-lines. Initial squeeze treatment costs were very high due to high pumping cost, particularly since a large number of wells had to be treated. An alternative scale inhibition method was therefore sought to reduce the treatment costs. The first trial of an encapsulated scale inhibitor treatment was performed in 1994 with encouraging results. Consequently, more wells were treated using the encapsulated scale inhibitor method in 1997 and subsequent years. Low MIC After monitoring residual inhibitor levels of the squeezed wells, it was recognized that a low threshold scale inhibitor concentration or MIC (minimum inhibitory concentration) requirement existed for the Ghawar Field.

Acid stimulation systems to remove formation damage are very well established for vertical injectors, drilled during the early development of a sandstone reservoir in central Saudi Arabia. With the advent of horizontal technology, new injectors are drilled with thousands of feet of horizontal section to expose large reservoir area for injection. The conventional acid stimulation programs, applied on vertical wells, would be impractical and very expensive for horizontal wells due to the expected large quantities of acid and other associated chemicals. An innovative acid stimulation approach has been introduced for stimulating sandstone horizontal injectors in central Saudi Arabia. The new approach, which has been applied on horizontal injectors, consists of a foam cleanout to condition the horizontal section followed by main acid stimulation using optimized acid volume and overdisplacement of spent acid into the formation. This innovative stimulation program provides an efficient and cost-effective method to condition the horizontal section by removing as much as possible of drilling mud cake, filtrates, and possible biomass. It also allows acid treatment to be optimized for stimulating the formation rather than only for removal of mud cake. This paper discusses in detail the successful application of the innovative approach and presents the post-job injectivity tests and results. Introduction & Background Oil production from the subject field started in December 1996. Water injection started in this field in August 1997 using a peripheral water injection pattern to maintain reservoir pressure. During the initial plan, all oil producers and injectors were completed as vertical wells. Due to oil demand, the production from the field was limited to a minimum rate from one well, while rotating production from well to well and water injection was shutdown in 1999. Currently, the field is being developed to produce at higher rate. Therefore, water injection is required to achieve the required production target and to maintain reservoir pressure. Due to low injection rate observed from vertical wells, it has been decided to drill new horizontal wells. The subject reservoir is an unconsolidated and heterogeneous sandstone. The mineralogical composition of the reservoir rock as indicated by bulk XRD analysis is given in Table-1. The rock contains considerable amounts of swelling (illite/smectite) and migratable (kaolinite) clays. It also contains several iron-rich minerals (chlorite and ankerite). Hematite is also detected in some core plug samples. The presence of high concentrations of iron-rich minerals suggests that an iron control agent should be used during acidizing this formation. In addition, the reservoir rocks contain carbonate minerals (calcite and ankerite). Finally, the rock contains feldspar.1–2 Based on extensive lab work and field experience, acid stimulation systems to remove formation damage were very well established for vertical injectors. The basis of this work was used to develop an acid stimulation program for horizontal injectors.

Passive completions, comprised of inflow control devices and external packers, are usually considered in horizontal wells, located in risky or mature areas. These completions are proven techniques for reservoir conformance to mitigate water or gasconing problems and ensure uniform production contributions along the horizontal section. After well completion or shortly after initial production, these wells may fail to sustain production, largely due to formation damage or plugging in the inflow control devices. The conventional acid program, applied on wells with non-passive completions, is not suitable on these wells, due to the risk of impacting the completion integrity to the extent that it will violate the installation purposes. The requirements of acid treating wells with the same completions become inevitable due to the increasing number of wells equipped with these completions in a major carbonate reservoir in Saudi Arabia. A smart approach has been developed through innovative thinking to stimulate wells equipped with passive completions. The new approach has successfully stimulated four wells and resulted in restoring well productivity. This smart stimulation approach demonstrates a competent method to clean out the ICD completion along the horizontal section and to remove formation damage.