Nugraha, Ikhsan

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.

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%.

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.

Gandhar is one of ONGC's major brownfields, discovered in 1983 and located in Gujarat. The Field produces approximately 30,000 bopd and is on decline.

A joint team from ONGC and Schlumberger carried out a rigorous process of candidate selection, fracture design, and implementation of fit-for-purpose technologies.

10 candidate wells were selected and the target zone was the GS-3A reservoir. 10-15ft above the GS-3A was a water bearing sand. Most of the candidate wells were primarily in an area of the reservoir that had experienced poor recovery primarily because of poor permeability.

There were unique challenges posed by the Gandhar candidate wells. Earlier attempts to fracture wells had been unsuccessful. In addition the water bearing sand posed a risk to successful execution; the fracture had to be contained within the zone of interest. High Pressure and high temperature operations posed additional challenges that had to be addressed.

For Fracture containment Schlumberger's Sonic Scanner tool provided rock mechanical stress data that was used to design the fracture to be contained within the zone of interest and not break into the water bearing sand above. It also provided the maximum stress direction to determine the preferred orientation plane for perforating. Oriented perforating assisted in achieving lower fracture breakdown pressures.

Fracturing fluids for high temperature (320 degF) operations were selected. Well design and equipment was considered for high pressure operations (10,000 psi surface pressure)

Using this process, 10 wells were successfully hydraulically fractured. Unfortunately, wells produced lower than expected; unforeseen in-situ emulsions are suspected as the cause for the production impairment.
In this paper we will describe the technology and processes brought to the project. Current results and impairment issues will also be presented.

Field Overview

Gandhar is one of ONGC's major onshore brownfields, discovered in 1983. It is located in the state of Gujarat, on the western part of India. More than 560 wells have been drilled in the field to target 13 major sands including the target sand - the GS-3A. The field has 238 oil wells, 67 gas wells, 122 water injectors and 18 gas injectors. Till date the field has produced 24.41 Mmt of oil and 8.48BCM of gas. The production is on decline as seen from production history plot (Figure 1).