Najmah-Sargelu Formations of Kuwait show considerable potential as a new unconventional hydrocarbon play and produces mainly from fractures. The key uncertainties which affect the productivity are the nature and distribution of permeable fracture networks, and the limits of oil accumulation.
This paper presents the results from whole-rock elemental analysis of three cored wells in UG field. The main objectives of this study are to use high-resolution elemental chemostratigraphy to gain a better understanding of the detailed stratigraphy and correlation of the Najmah-Sargelu Formations, to assess the chemo-sedimentology for determining the intervals of high organic content, to estimate the mineralogy of the sequence using an algorithm developed for an analog formation in North America; and to determine the most likely intervals to contain fractures, using a brittleness algorithm.
A clear chemo stratigraphic zonation is recognized within the Najmah-Sargelu Formation. The larger divisions are driven mainly by inherent lithological variation. The finer divisions are delineated by more subtle chemo stratigraphic signals (K2O/Th and Rb/Al2O3 ratios) and preservation of organic matter (high V, Ni, Mo, and U abundances). Zones of alternating brittleness and ductility are clearly identified within the interbedded limestones and marlstones of Najmah-Sargelu Formation.
Two unexpected but important features of the Najmah-Sargelu limestones were elucidated by the elemental data. Brittle, high-silica spiculites, with virtually no clay or silt, are more common than previously recognized from petrophysical logs and core descriptions in the upper Najmah limestones. In addition, the limestones adjacent to the spiculites tend to contain bitumen as pore-filling are recognized by the trace metal proxies. Ternary plots of V, Ni, and Mo differentiate the combinations of kerogen and bitumen present in the Najmah-Sargelu Formations.
The clarity and sensitivity of the chemostratigraphic signals are sufficient to enhance formation evaluation, and can also assist borehole positioning using the RockWiseSM ED-XRF instrument at wellsite.
The cold-production-recovery process, also known as cold heavy-oil production with sand (CHOPS), is a method for enhancing primary heavy-oil production by aggressively producing sand. It is successful in vertical (or slanted or deviated) wells in western Canada. In this process, large amounts of sand are produced on a continuing basis along with heavy oil. Attempts at cold production in horizontal wells have not been particularly successful. When sand production has been generated in horizontal wells, these wells have tended to become plugged with sand.
This paper presents the results of experiments performed to assess the feasibility of applying cold heavy-oil production in horizontal wells that have been completed with slotted liners using less-aggressive (i.e., managed) sand-production strategies. Specifically, the effects of slot size, confining stress, fluid velocity, and sand-grain sorting on sand production were investigated.
The results indicate that slot-size selection is critical for establishing "sand on demand." From the experiments, a correlation between slot size and controlled sand production was found for well-sorted sands. This correlation should allow for the specification of appropriate slot sizes for target reservoirs containing well-sorted sands.
In the experiments, when flow rates resulted in low but persistent sand production, channels and/or elliptical dilated zones were created that greatly enhanced the effective permeability near the slot. This observation suggests that producing at low and steady sand cuts for a long period of time might bring two benefits: a way to transport the sand out of the well without causing plugging and the creation of high-permeability channels or zones that can improve production from the reservoir.
To summarize, if the appropriate slot size were combined with the right drawdown rates, controlled sand production could be achieved, with attendant significant increases in permeability. This suggests that substantially increased oil-production rates could be achieved from horizontal wells if sand-production rates could be maintained at low but persistent levels.
Mud acid, which is composed of HCl and HF, is commonly used to remove the formation damage in sandstone reservoirs. However, many problems are associated with HCl acid, especially at high temperatures. To overcome many of these drawbacks, organic-HF acids have been used as an alternative to mud acid. However, very limited research has been performed to reveal the reactions between organic-HF acids and minerals in sandstone reservoirs.
In this study, formic-HF and acetic-HF acids were examined to react with various clay minerals (kaolinite, chlorite, and illite), in comparison with mud acid. A series of acid mixtures with different ratios and concentrations were tested. Inductively coupled plasma (ICP), scanning electron microscopy (SEM) and 19F nuclear magnetic resonance (NMR) were employed to follow the reaction kinetics and products. Core flood experiments on sandstone cores featured with different mineralogy, with dimensions of 1.5 in. × 6 in. were also conducted at a flow rate of 5 cm3/min. The core effluent samples were analyzed to determine concentrations of Ca, Mg, Fe, Si, and Al by ICP.
Both formic-HF and acetic-HF acids are much milder than mud acid. The species and amounts of reaction products of different clay minerals in organic-HF acids depend on mineral type, acid composition, and ratio. This conclusion is further confirmed by core flood experiments, in which sandstone cores with different mineral compositions give quite different responses to the same acid mixture. This paper will discuss the detailed chemical reactions that occurred within cores and were followed by chemical analysis of core effluent samples.
Different organic-HF acid mixtures have been used to stimulate sandstone formations. Typically, they are used as alternative to regular mud acid in order to overcome its potential limitations such as rapid spending, high corrosion rate and incompatibility with sensitive clays. However, organic-HF systems are more susceptible to fluoride-based precipitations because they contain high amount of free fluoride ions. This paper focuses on identifying the type of precipitations that occur during reactions of organic-HF acids, and on determining the factors that affect these precipitations.
Solutions of different organic-HF acids namely formic, acetic and citric acid, containing HF concentrations of 0.5, 1 and 1.5 wt%, were examined in this study. Aluminum chloride or iron chloride were added separately to each organic-HF acid solution to contain 1,000; 5,000 or 10,000 mg/L of aluminum or iron (III) ions, respectively. The acid mixtures were neutralized by adding sodium hydroxide. Filtered solutions were analyzed using inductively coupled plasma (ICP) to assess the ability of used acids to hold Al and Fe (III) dissolved ions, while formed solid precipitates were analyzed by X-ray diffraction (XRD).
The type and amount of precipitates were found to be mainly dependent on solution pH, organic-HF type, and initial free fluoride concentration. All live organic-HF acids containing dissolved iron (III) showed no precipitation even after iron (III) level reached 10,000 mg/L. However, when solution pH value was raised, none of tested organic-HF acids were able to prevent iron fluoride precipitation. On the other hand, the main factor that controlled the aluminum-fluoride precipitation was found to be F/Al ratio. It was found that there is a critical F/Al ratio, above which the aluminum fluoride precipitation occurred.
Mud acids containing different HCl/HF ratios have been extensively used to dissolve primarily clays, feldspars and to less extent silica and thus increase well productivity or injectivity (Smith and Hendrickson 1965, Gidley 1985, Brady et al. 1989, Shuchart 1995, Gdanski and Shuchart 1996, Thomas et al. 2001, Hartman et al. 2003, Taq et al. 2009). While HF is the main reactant with formation rocks, HCl is inevitably added into the mixture to reduce HF consumption as well as maintain acidic environment and subsequently prevent precipitations of HF reaction by-products. Despite the reasonable success of mud acid, critical drawbacks associated with using the mud acid have limited its use. One of the most potential limitations of mud acid is rapid spending, especially at elevated temperatures, which results in subsequent precipitations of reaction products following secondary and tertiary reactions and limits acid penetration in the formation as well (Gdanski 1996, Thomas et al. 2001). A combination of these precipitations, matrix unconsolidation, presence of HCl-sensitive clays, and high corrosion rates has resulted in variable success rate of mud acid stimulation treatments or even worse in further formation damage (Simon and Anderson 1990, Gdanski 1996, Thomas et al. 2002).
Kaolinite migration is a common but often well treated formation damage mechanism. Undesired secondary reactions leading to precipitates and/or limited treatment coverage related to the presence of additional damage mechanisms are common issues. The present work documents a field case study of kaolinite damage control that included dissolution and stabilization under a very unfavorable environment in which CaCO3 scales and asphaltenes also co-existed. The case herein described is the last development stage after several unsuccessful trials in the same area which included the injection of conventional mud acid and retarded HF sandstone type systems. A new chemistry approach incorporating retarded flouboric acid generation and high performance chelants for metallic ions control was developed. Also key, was realizing fines wettability to oil (through critical rate tests to both water and oil) which allowed including proper pre-flushes on final treatment deployment. Along with a summary of the fines problem description in the area of interest, laboratory protocols, stimulation design approach and field trial results are presented. According to treated well results, up to 50% PI improvement could be now attained in ~60% of total well count where same damage configuration is expected to be present.
Barco is a tertiary formation producing compositional fluids ranging from gas condensate to the top of the structure to volatile oil towards the base. Typically fine to coarse grained quartzarenites / poor to moderately sort are encountered. Static reservoir temperature is 260 !F and four flow units are clearly differentiated according to petro physical properties (table 1). In terms of mineralogy, Barco is 90 - 95% quartz with 5 - 10% clays. Migratory clays such as Kaolinite (2% to 7%) and illite are the most common. Figure 1 shows a typical mineralogy composition of drilling cuts taken at different depths of a lateral well that navigated through a damaged zone of an original Barco producer.
Well productivity enhancement in Barco has been a challenging task. Presence of compositional fluids is a common issue for proper damage diagnosis and control. Summary of formation damage mechanisms is as follows:
- Inorganic scales: Calcium carbonate and barium sulphate are common scales related to natural occurrence of Ca and Ba and mixture of injection and production waters. Historically, stimulation approaches has included the usage of hydrochloric and acetic acid, and more recently EDTA and phosphonate based chemicals for dissolution and inhibition.
-Organic deposits: Asphalting deposits takes place by near-wellbore drawdown, natural depletion, and compositional changes related to natural gas injection (75% CH1, 10% CH2, 5%CO2). This phenomenon becomes more critical at lower zones due to the presence of a compositional gradient which implies higher degree of sub-saturation with depth.
- Wettability changes: Especially in zones where organic deposition exists. Critical rate measurements at different depths confirm this (figures 2 and 3).
- Fines migration: This damage mechanism is the core of this study.
Mud acid, which is composed of HCl and HF, is commonly used to remove the formation damage in sandstone reservoirs. However, many problems are associated with HCl acid, especially at high temperatures.
In this study, formic acid was used to remove carbonate minerals as a preflush and with the main HF stage. A series of formic acid and HF mixtures with different ratios and concentrations were tested. Sandstone cores featured by different minerologies with dimensions of 1.5 in. × 6 in. were used in the coreflood experiments, which were run at a flow rate of 5 cm3/min and temperatures from 77 to 350oF. The cores were analyzed by CT scan before and after the acidizing to investigate the effect of the acid. The core effluent samples were analyzed to determine concentrations of Ca, Mg, Fe, Si, and Al by ICP. 19F NMR was utilized to follow the reaction kinetics and products. Zeta potentials of clay particles (kaolinite, illite, and chlorite) were measured in various acid solutions
Formic acid (9 wt%) damaged sandstone cores. Zeta potential measurements indicated that formic acid can trigger fines flocculation. Addition of 5 wt% ammonium chloride helps to shield negative charges on clay surface. Analysis of core effluent samples indicated that there was CaF2 precipitate in the core when a small volume of preflush was used. Coreflood tests highlighted that formic acid/HF caused loss of core permeability. This paper will discuss the detailed chemical reactions occurred within cores and were followed by chemical analysis of core effluent samples and 19F NMR. Secondary reaction between clay minerals and HF became faster at higher temperature, and decreased the ratio of Si/Al. It was also found that different clay minerals react with HF offering very different concentrations of Al and Si in spent acid.
Reservoir drilling and completion fluids are affected by temperature. Fluids that perform well at one temperature range can experience major problems at higher temperature ranges. A series of studies have been conducted over the last four years looking in detail at the effect of reservoir drilling fluid design for high-temperature, high-pressure (HTHP) reservoirs, with significant developments in the understanding of the role of fluid loss additives. The focus of these studies was to reduce and control formation damage, in addition to allowing efficient drilling and effective logging of exploration wells. This paper reviews and explains the findings of these investigations and the significance on past and future reservoir exploration and drilling operations.
The studies were all required to assist in a number of specific drilling campaigns where logging of reservoir pressures was planned or had been performed and was believed to be influenced by formation damage. The investigations were initiated with sufficient time to allow hundreds of formulations to be tested with regards to drilling properties, stability and formation damage.
Very distinctive improvements in HTHP return permeability and filter cake thickness were obtained, which was accompanied by logging success. The most notable controlling factor of return permeability under HTHP conditions was determined to be the fluid loss additive. The selection and quantity of fluid loss additive was so significant that it alone could vary the return permeability by more than 80%.
The findings from these investigations have been put to practical use in a number of exploration wells where pressure measurements have been taken with great success. One notable investigation focused on a formulation used 10 years ago on a reservoir where pressure measurements could not be taken. The reservoir was abandoned until recently due to the apparent lack of pressure. This paper details the problems encountered and the results of the investigation in addition to the techniques used to prevent similar problems occurring again.