Low permeability oil and gas-bearing carbonate formations are routinely completed with open hole horizontal laterals and multistage fracturing treatments to achieve maximum reservoir contact and enhance production of the formations. This completion technique has been successfully used in previously non-economical reservoirs — in North America and around the globe — to make them commercial.

Open hole multistage fracturing technologies have been deployed in tight gas carbonate reservoirs to improve well productivity while using reservoir simulations to optimize the fracture design. When applying multi-stage fracturing one of the key aspects is to assure the isolation between the stages to induce independent fractures. This goal becomes even more challenging to achieve when the process is an acid fracturing treatment. Hydraulic communication between the fracture stages has been previously observed, which has prevented the creation of separate fractures transverse to the wellbore, thereby resulting in fewer and shorter fractures, mostly created along the wellbore plane. In many cases, new fractures could not even initiate and only matrix acid treatments could be conducted.

To overcome the isolation challenge during an acid treatment, a multistage completion assembly based on sliding sleeves and swellable packers has been devised and implemented to conduct selective acid fracturing in low permeability carbonate reservoirs. This combined system has mechanically simplified the multistage fracturing job, reducing costs and complexity compared with traditional cement and perforating methods. The system provides excellent isolation between consecutive treatments by providing positive annular barriers. The technology ensures that the entire lateral is treated uniformly and according to the design, enhances proper fracture placement, increases reservoir contact area, and improves well productivity.

This paper describes and addresses the successful deployment of this completion and fracturing technology. The success resulted from careful planning, fluid testing, and a comprehensive completion design that was fit-for-purpose to provide optimal stimulation treatment and productivity enhancement.

One of the major challenges in mature oil fields is to improve recovery from existing fields by developing and implementing new technologies that make operations efficient and cost effective. For a reservoir with a water or gas drive mechanism, the mobility ratio between oil and water or gas becomes more critical due to the lower viscosity of water or gas. Observably, breakthroughs can occur within relatively short periods of production time. Once breakthrough occurs, gas or water production can rapidly dominate production prompting well intervention or the shutting-in of production, leaving unrecovered oil behind. Inflow control device (ICD) and autonomous inflow control device (AICD) have shown oil production and recovery can be increased significantly with better inflow control/pressure regulation along the lateral, which to some degree has resulted in breakthrough delays. However, neither ICD nor AICD are able to shut off unwanted gas and water production completely. The autonomous inflow control valve (ICV) offers the functionality of conventional ICD and can actively shut off unwanted fluid completely. The paper describes the development of Autonomous ICV, experimental test results, and preparations prior to the completion installation. The main challenges and conclusion from the field tests are presented and discussed based on the initial flowback data where the functionality of Autonomous ICV was verified, i.e., by shut-off of low viscosity fluid, such as water, and opening for oil with higher viscosity.

Abstract

In Saudi Arabia, conventional oil reservoirs have been treated using conventional stimulation methods. The challenge is that many of the formations now are tighter and require improved stimulation methods. Fracturing is a major topic discussed in the industry as of late and as such, using it in this formation will serve as a trial to shift from conventional stimulation methods to fracturing when facing tighter formations.

This particular acid frac was performed in a tight carbonate formation. The chosen well is a newly drilled trilateral producer completed with a multistage frac completion in the motherbore and will serve as a pilot well for this reservoir in the area. The acid frac was a seven stage completion utilizing hydraulic fracturing. Several methods using pressure and injection were used to determine reservoir fracturing response and petrophysical properties.

This paper will discuss the first multistage acid frac performed in an oil producer in Saudi Arabia. It will examine the entire process of candidate assessment, job preparation, and execution. In addition, the paper will discuss challenges faced, solutions taken, and the post-decision results. The paper will show how an injectivity test performed pre- and post-frac was used as a benchmarking tool to analyze the effectiveness of the frac. Finally, we will discuss the flow back of the well, initial results, lessons learned, and optimization of future jobs.

Abstract

In recent years, multistage fracturing completion has been adopted by many operators across the globe as a primary means to maximize reservoir contact. To succeed, this completion strategy must be complemented with good understanding on petrophysical and geomechanical properties of the reservoir; which resulted in a better understanding of fracture orientation and decisions on open hole length, number of fracturing stages, packers and frac ports placement. 

When dealing with a low permeability environment, for a specific open hole length, it is almost certain that increasing the number of fracturing stages will potentially give the highest productivity. Subsequently, this will also potentially increase the chance of having packer integrity issues due to the shorter distance between the frac port and packers.

Currently, the most common practice to evaluate packer integrity is done on-site, by comparing pressure response at a constant injection rate before and after opening a frac port, in addition to observing breakdown and closure pressure for each compartment. In the event of similar pressure response on both sides, it may be an indication of communication. Consequently, relying only on this injection exclusively is not sufficient because the leak-off profiles may suggest otherwise and could lead to drawing the wrong conclusions.

This paper describes a new enhancement of the mini fall off (MFO) injections procedure, which can be used to confirm multistage fracturing packer’s integrity on-site. The procedure consists of performing injection with similar small volume and rate before and after opening the frac port, overlaying pressure responses, pressure decline analysis, as well as comparing pressure derivative for both injections. This technique has been successfully tested on-site where one out of seven stages planned were identified to have communication and has helped in the decision making process to skip the stage and avoid stimulating the same compartment again.

This paper presents a case study of a matrix acidizing treatment in a well located at the neutral zone between Kuwait and Saudi Arabia, whereby the combination of a "smart fluid?? in a stimulation treatment pumped through a Coiled-Tubing (CT) with the real time distributed temperature sensing (DTS) technology helped improve the real-time decision process of fluid placement, temporary plugging placement, and treatment efficiency evaluation. As part of the analysis process and to facilitate the onsite decision-making process, a temperature inversion technique was also used to translate the actual temperature profiles into fluid invasion profiles across the horizontal open-hole section of the well. Additionally, a full scale acid placement and thermal modeling is proposed in order to perform an in-depth post-treatment evaluation. The bottom hole data evaluation further confirmed the benefits of using a smart fluid. Following the treatment, the well produced at a rate of 1500 bbl/day with 17% water cut, which is well below the field average of ~50%.

This reference is for an abstract only. A full paper was not submitted for this conference.

Multilateral wells pose a unique challenge to operators when planning for any intervention. Correctly accessing and uniformly acidizing all laterals continues to be challenging. While lack of reliable downhole data and knowledge about naturally fractured zones or poor correlation between porosity and permeability in carbonates limit the effectiveness of a stimulation treatment; sometimes the inability to access all laterals even prevents the lateral from being acidized at all. These limitations in acidizing, therefore, provide lower than expected gains.

Selective lateral access by using coiled tubing multilateral entry tools (CTMET) have provided a first step to selectively place fluids in each lateral. However, even selective lateral access cannot provide positive confirmation that treatment fluids are confined to the intended lateral. New downhole measurements with fiber optic assisted coiled tubing (FOACT) seek to mitigate some of the uncertainty that prevails in such well interventions.

This paper describes an innovative approach adopted for the stimulation of a tri-lateral open-hole carbonate oil producer in Kuwait. The distributed temperature survey (DTS) and real time downhole data obtained from FOACT was used in conjunction with the CTMET to map and access all laterals. The DTS profiles were used to track real-time temperature changes between fluid stages of a stimulation treatment. Identifying and prioritizing which lateral to stimulate first, lateral injection distribution, formation fluid invasion, diverter efficiency and changes to the injectivity profile were interpreted in real time to improve the fluid placement.

The paper describes the effect of combining MLRT (multi lateral reentry techniques) with the fiber optics technology simultaneously and the lessons learned from this innovation. This synergistic approach not only improved operational efficiency, well-site safety but also resulted in reviving production from a previously dead well in a cost effective manner for the operator. As a result, the entire approach towards multi-lateral well stimulation in Kuwait was revolutionized with renewed confidence towards achieving better results in future interventions.

Carbonate scaling is one of the common problems that occur in wells producing high amount of water. The tendency of scaling escalates in mature fields. This problem becomes critical in sub-hydrostatic wells with Electrical Submersible Pumps (ESP). In such cases, the scale not only reduces the flow of fluids into the wellbore, but also causes frequent failures in downhole equipment, eventually stopping production leading to well workover. Frequent ESP failures can increase the operating costs to unacceptable levels which may eventually lead to field abandonment.

Joint Operations (Chevron and KGOC) in Partitioned Zone (PZ) faced severe scaling problems in Humma field producing from Marrat Carbonate reservoir. A thick layer of calcium carbonate scale was observed in the completion string during the workover. As a result of this scale, ESP repair and replacement frequencies increased abnormally. Also, the ESP amperage charts showed erratic behavior due to solids interference inside the pump resulting in pump failures.

A combined scale control and stimulation treatment was applied in three wells in Humma field in Joint Operations to slow down scaling tendency in the formation and tubular. These wells are producing up to 1523 BWPD averaging 28% water cut. The treatment provided effective placement of scale inhibitor in the formation while controlling any increase in water production because of stimulation. As a result, the workover frequency due to pump failures was reduced. Not only did the production improve, the amount of deferred oil was also significantly reduced resulting in direct oil gain and significant savings in operating costs.

This paper describes the lab analyses, treatment design and execution procedure, adopted for the implementation of this technique as well as the recommendations and lessons learned from the field experience.

Brief Review of Scale Problem
Numerous studies have been done to understand the scale in oilfield. Subjects are very wide covering scale behavior, deposition, identification all the way down to treatment and inhibition chemicals. In the subject of material selection Wang, Z (2005) reported that the surface can be engineered in order to decrease the scale formation and adhesion. Minimizing the surface roughness and number of hooking sites can decrease the extent of scale deposition.

From the treatment point of view various technique has been employed to introduce scale inhibitor into the well even beyond matrix rate, in the effort to maximize the amount of inhibitor can be placed in the well, hence extend the scale protection. In 2001, Norris, et al, published a report that the uses of scale inhibitor impregnated proppant in the fracturing treatments were able to get acceptable scale inhibitor residual.

In order to achieve successful scale control, it is required to take a holistic approach and looking at the scale within the frame of total production system from reservoir to completion and all the way to surface. For that, the first question should be to predict whether a reservoir with the existing production system will have scaling tendency sometimes during its production life. Brown, M (1998) reported a loss of production in one of North Sea well from 30,000 BOPD to zero in just 24 hours. This shows that the predicting scale tendency and its magnitude are not an easy task.

One of the most common strategies to effectively produce from tight gas carbonate reservoir is by completing the wells with acid fracturing technique, where the etched fracture half length alters the flow pattern from formation in to the wellbore with its high conductive flow path.

The treatment success, apart from operational aspects, is also measured by addressing the issue of fractured geometry created, zonal coverage achieved and the actual well potential based on its petro-physical and rock mechanical properties and relate this to well's production behavior. In the high pressure/high temperature tight rock formation with minimum number of natural fractures, it is very common to observe immediate production gain following an acid fracturing treatment.
The well in discussion was acid fractured 3 years earlier with almost 90% of cumulative production occurred during the last one year. It was observed that it is declining faster than expected. Review of the well performance led to two main possible causes, i.e. reservoir pressure decline and reduction in fracture length/conductivity. Acid re-fracturing strategy was considered and decided to restore the well's productivity by further extending the fracture half length by enhancing the fracture conductivity.

The results showed that Productivity index (PI) increased by 2.5 folds during the post treatment production test. However, after 3 months of continuous production, the PI declined down to 1.2 folds despite the pressure build up performed indicated fracture conductive behavior. This paper discussed key lessons learned to further improve the outcome by integrating production analysis, reservoir quality evaluation as well as stabilized production expectation with stimulation approach during candidate evaluation process.

Several unknowns still remain in carbonate matrix acidizing. Poor correlation between porosity and permeability in carbonate formations, the possibility of natural fractures and limitations in the economically practical number of core samples often result in a largely unknown permeability variation across the pay. Intelligent fluid systems have been developed to address such uncertainty, but the lack of real time downhole data during the treatment typically prevent confirmation of the fluid system efficiency.

For well bore access, coiled tubing intervention often provides a quick and economically attractive alternative to the work over rigs, but both types of intervention have always been limited with their ability to provide downhole data. Typically, for both coiled tubing and workover interventions, a reliance on surface measurements to make inference about the downhole conditions has been used. However, mechanical and chemical processes in the near wellbore, downhole fluid movements and the above mentioned unknowns in reservoir properties make surface readings a poor estimate of true downhole conditions.

New downhole measurements provided with fiber optic enabled coiled tubing (FOECT) attempts to address some of these limitations. This novel approach deploys a downhole sensor package with fiber optic telemetry through a protective umbilical inside the coiled tubing string. The downhole sensor package provides real time temperature, pressure and depth readings with a casing collar locator, allowing the operator quantitative feedback of downhole conditions during treatment. The use of fiber optic telemetry additionally allows recording of distributed temperature surveys (DTS) for obtaining high resolution temperature profiles across the entire wellbore.

Combined interpretation of the real time downhole data and the DTS profiles enables real time feedback during and between the different stages of carbonate openhole stimulation. With DTS, fluid placement as well as changes to the injectivity profile can be interpreted at key stages of the treatment and necessary changes to the planned treatment can be implemented accordingly.

This paper outlines recent case histories, where for the first time in Kuwait fiber optic enabled coiled tubing was used to optimize stimulation treatment for the operator. These candidate wells were sub-hydrostatic pore-pressured horizontal openhole producers, completed with an electrical submersible pump (ESP) for artificial lift. The DTS system enabled the operator to identify both high permeability zones as well as tight zones across the entire openhole section. This enabled the operator to take pro-active decision on where to spot diverter and acid during the treatment. This new and modified approach to stimulation not only helped in improving production but also resulted in marked changes in treatment volumes as dictated by the DTS measurements.

The implementation of this fiber optic enabled coiled tubing workflow had a significant impact on the operator's confidence with carbonate matrix acidizing, as very limited downhole data was available for informed decisions to optimize stimulation treatments. As such, the downhole data obtained from the fiber optic enabled coiled tubing stimulation not only helped in optimizing the stimulation treatments but also help the operator to get a better understanding of the reservoir.