No abstract

Drilling wells with longer horizontal sections to maximize the reservoir contact has brought many challenges to the well interventions using Coiled Tubing (CT). In most cases, the complexity has pushed the CT interventions to the limits, driving the development of new solutions to extend the reach to the total well depth. The number of these extended wells has grown significantly in recent years in Saudi Arabia, especially in new development fields like the study area, where more than 100 extended reach power water injection wells were placed in the reservoir flanks. The water injection wells in this study area are a typical example of complexity due to the combination of large bore tubular, lower reservoir pressure, and long horizontal openhole completion, with lengths between 4,000 to almost 8,000 ft. During the initial CT interventions in this field, several challenges were encountered, e.g., stuck CT due to pressure differentials and slack-off weight through severe doglegs, tight spots, and other obstructions. Extensive knowledge was gained by performing an extensive simulation and study of the horizontal section geometry, and analyzing the operational data. Based on the findings, a combination of techniques was introduced to the CT intervention procedure, to extend the reach and minimize the operational problems and costs. The key components of our new implemented methodology were buoyancy reduction by using nitrified fluids and friction reduction by using new viscoelastic surfactant (VES) friction reducer. In addition, combinations of other techniques were employed, e.g., optimizing the pull tests frequency in openhole and improving CT movement practices. This paper shows the effectiveness of the new cost effective and reliable methodology to maximize the CT reach up to 8,000 ft allowing the distribution of the acid stimulation throughout the entire horizontal sections. INTRODUCTION This paper is based on the CT stimulation campaign performed in one of the new fields in Saudi Arabia that is being developed by drilling extended reach horizontal water Injection wells (Figure 1) in the flank of the reservoir to assure the effective water distribution, optimum sweeping and pressure support in the reservoir. Acid stimulation using CT is not an easy process due to the wellbore architecture, length of the horizontal section, reservoir hetrogentiy, low reservoir pressure, damage distribution, etc. For carbonate formation, the success of HCl acid stimulation depends on the placement and effective acid distribution along the entire openhole. Although CT represents the most effective placement method in a horizontal section, it has some limitation especially on extended reach wells with complex configuration. The definition of an extended reach well is a well with a measured depth to true vertical depth ratio (MD/TVD) equal to or greater than 2.

Drilling new generation wells with longer horizontal sections, to maximize the reservoir contact, has brought many challenges to well interventions using Coiled Tubing (CT). In most cases, the complexity has pushed CT interventions to the limits, driving the development of new solutions to extend the reach to total well depth. The number of these extended-reach wells has grown significantly in recent years in Saudi Arabia, especially in this new development field where more than 120 extended reach water injection wells were placed in the reservoir flanks. The water injection wells in this study area are complex due to the combination of large bore tubular, lower reservoir pressure and horizontal openhole (OH) completion, with lengths from 3,000 ft to almost 5,000 ft. During the initial CT interventions in this field, several challenges were encountered, e.g., stuck CT differentials, slack-off weight through severe doglegs, tight spots, and other obstructions. Extensive knowledge was gained by performing an extensive simulation, studying the horizontal section geometry and analyzing the operational data. Based on the findings, combinations of techniques were introduced to the procedure to extend the reach and minimize the operational problems and costs. The key components of our new implemented strategy were buoyancy reduction by using nitrified fluids and new viscoelastic surfactant (VES) friction reducer or drag reduction agents. In addition, combinations of other techniques were employed, e.g., optimizing the pull tests frequency in the OH and improving CT movement practices. This paper discusses the difficulties and challenges of the initial stage of the stimulation campaign, performed in horizontal OH water injector wells using CT. Also, it presents the results and analysis of the effect of buoyancy, CT pipe size and new friction reducer for the referenced wells. The study leads to a new cost effective and reliable technique, which once implemented, conduces to maximize the CT reach without using mechanical devices, e.g., agitators or tractors. INTRODUCTION The study was performed in one of the new fields being developed in Saudi Arabia by drilling extended-reach horizontal water injection wells in the flank of the reservoir to help assure the effective water distribution, optimum sweep and adequate pressure support in the reservoir. Stimulation of the new water injection wells is a key factor for new increment success. The horizontal wells were acid stimulated, in order to remove formation damage and enhance the water injection. Distribution of treatment on the whole horizontal section is essential to implement the depletion strategy and maximize recovery factor. The length of horizontal OH section varies between 3,000 ft and 5,000 ft.

This paper will present calculation techniques to predict the cross flow rate resulting from a casing leak in a water injection well. The techniques do not require the conventional use of downhole flowmeter (spinner) to obtain the flow rate. Rather, continuous surface injection data prior to leak development and shut-in well data are used to estimate the casing leak cross flow rate. Well performance modeling and nodal analysis techniques were deployed to carry out the computations associated with the proposed method. The case study of this paper is a tubingless water injector. The well was identified with an upward cross flow by a sudden drop of wellhead pressure to zero psi. To quantify the leak cross flow rate, the following calculation methodology was applied: Generating a well performance model using pre-leak injection data: The case study's physical dimensions, most recent static bottomhole pressure, and injection pressures and rates are all used to build the inflow performance model (IPR). The calculated IPR is then calibrated using the wellhead (surface) injection pressures and rates data. Generating an imaginary production well model: A production well mimicking the flow characteristics and properties of the case study is envisioned to simulate leak cross flow at shut-in conditions. The imaginary production well has the same reservoir pressure of the injection well and the productivity index of the imaginary well is assumed to be equal to the injectivity index of the injector. The imaginary production well's system node is selected to be at the leak point and performance curves are generated at different system's node pressures. Calculating the system's node pressure of the imaginary production well: The pressure across the leak point is needed as an input to the production well model (which simulate the cross flow rate). The leak zone and water level depths were identified using a gauge ring survey. Hence, the system's node pressure was calculated using Bernoulli energy balance equation. The results of this numerical methodology was verified by running an e-line deployed flowmeter (spinner survey). The results of the numerical methodology was 1.37 % over the actual spinner rate measurement.

The paper outlines operational challenges during the well securement of a Power Water Injector (PWI) completed in the reservoir oil-water contact (transition zone). Surface integrity issue arose in Well-A necessitating the installation of adequate downhole barriers to carry-out surface remedial repairs safely. Well isolation shut-offs were not successful in eliminating surface pressure to meet the minimum stipulated operational requirements for this field. Well operator's barrier philosophy mandates the presence of two shut-offs; one of which is mechanical, to allow removing surface control equipment during rigless operations in power water injection wells with positive wellhead pressure. Water flooding strategy in Field-A calls for drilling water injectors at the flanks and maintaining a peripheral injection scheme. However, as more wells are placed towards the crust of the reservoir to sweep the remaining oil behind the flood front, this well placement strategy leaves behind a transitional zone where more than one fluid phase is present. Formation evaluation logs conducted on Well-A indicated that the completed reservoir interval lies within the oil-water-contact. Typical well completions for PWIs in Field-A use large casing sizes up to 9-5/8 in. of outer diameter. Bullheading pumping technique is conventionally sought as the primary securement method for water injectors. However, hydrocarbon displacement with kill fluid in such types of completions is challenging given that the hydrocarbon displacement velocity is often surpassed by its segregation velocity. Attempts to eliminate the persistent wellhead surface pressure build-up in Well-A were unsuccessful. Fluid circulation was then, applied to Well-A. Heavy fluid was forward-circulated against a blank mechanical plug installed below the wellbore oil-water interface which was detected by a wireline gradient survey. Accordingly, compromised wellbore fluid was displaced. This technique has set the pace for future well securement operations in PWIs completed in the reservoir transition zone.