Kuwait has a considerable reserve of untapped heavy oil; plans were developed by KOC and embarked on a project to increase its oil production by 2020. Heavy oil production is an ambitious project and will be significant contributer to the overall increase in oil procuction capacity.
As the term "heavy oil?? suggests, it is a very viscous oil. The most common methods of heavy oil recovery are:
- Cold Heavy Oil Production with Sand (CHOPS)
- Cyclic Steam Stimulation
- Steam Flooding
- Steam Assisted Gravity Drainage (SAGD)
With the focus on the second method, Cyclic Steam Stimulation to enhance the recovery of heavy oil, the design of the cement became important in terms of endurance over the life of the well. In this technique the casing / cement would be exposed to steam injection temperatures as high as 500°F.
In such cases, the cement sheath may crack due the extreme forces acting on the thin sheath of the cement. It is therefore important to know the Young's modulus of both the formation and the cement. This will allow the slurry properties to be adjusted by the use of additives to lower the Young's modulus of the cement to less than of that of the formation. This will prevent damage to the cement sheath.
A fit-for-purpose cement slurry was designed accordingly and applied on a South Ratqa well. Well testing during and after 45 days of steam injection demonstrated that the cement maintained its integrity despite the challenging conditions.
Cement Slurry Design
A project was initiated to investigate the mechanical integrity of various cement slurries subjected to 500°F steam-injection cycles. The overall aim was to achieve a flexible cement design that would withstand the induced stress applied in this particular situation. (Figure 1).
Live samples (cement, location water and additives) were air-freighted to the USA (Baker Hughes Pressure Pumping Technology Center in Texas) to avoid any design flaw factors, and maintain reproducible slurries upon actual job execution.
The cement slurry testing was done as per the schedule shown in Figure 1. This schedule was applied to most testing, including the determination of the following parameters:
- Destructive compressive strength
- Ultrasonic compressive strength
- Unconfined tensile strength
- Confined tensile strength
- Ultrasonic Young's modulus
- Ultrasonic Poisson's ratio
- Confined Young's modulus
- Confined Poisson's ratio
Two giant faulted domal structures are separated by a narrow saddle on the northern extension of Burgan Arch in Kuwait. The structures hold oil at multiple levels in Zubair, Burgan, Mauddud and Tuba Formations with varying entrapment mechanisms. The Zubair Formation is a major oil reservoir in Eastern structure but water wet in the structurally higher Western structure while the Tuba Formation is oil bearing only in the West and wet in East.
Multiple phases of oil migration, filling, up-fault migration and spilling of the traps due to tilting and faulting have been postulated from an integrated study of geochemistry, trapping mechanism and structural history. The early charge of immature and bio degraded oils have been replaced by more mature lighter oil. Part of the spilling and redistribution of oil is due to the structural tilting initiated during the Zagros orogeny. Deeper relict oil, geometry of a heavy-oil wedge, presence of higher porosity in carbonates, residual oil rims below the original oil water contacts indicate structural tilt towards the north and west. Another interesting feature is the presence of high asphaltene oil in the form of a massive "mushroom?? plug in the central part surrounded by lighter oil in and Burgan formation of western structure. The immovable oil and nearby lighter oil at same depths have similar biomarkers indicating a common source but different spill/charge histories. The lighter hydrocarbons have moved up through faults in the crestal area leaving behind the asphaltene rich heavy oil. In Eastern structure, the major part of Zubair is devoid of movable hydrocarbons in structural traps due to up-fault migration, lesser charge and inefficient seal of cavernous Shuaiba limestone. In contrast, giant structural oil traps in Western structure are to due to the smaller oil leakage along the less intense faults and more charging from the southwest. Additional support to the migration theory is that all the overlying traps are filled to spill point other than Zubair. Hydrocarbons are trapped in Burgan and Mauddud due to seals provided by carbonate cemented sands of Middle Burgan and marine shales of Wara.
Understanding the redistribution of oil in structural traps and the basinal oil charging have been pursued in discovery and delineation of the stratigraphic traps of Zubair and Ratawi Formations of the Eastern structure. These traps are much smaller compared to the giant structural traps.
Al-Ghamdi, Saleh Ali (Joint Operations) | Al-Najim, Abdulaziz (Joint Operations) | Al-Khonaini, Talal (Joint Operations) | Bouyabes, Ahmed Nouman (Kuwait Gulf Oil Company) | Nugraha, Ikhsan (Schlumberger Oilfield Eastern Limited) | Hamid, Saad (Dowell Schlumberger)
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.
Berlin, Jacob M. (Rice University) | Yu, Jie (Rice University) | Lu, Wei (Rice University) | Walsh, Erin E. (Rice University) | Zhang, Lunliang (Rice University) | Zhang, Ping (Rice University) | Chen, Wei (Nankai University) | Kan, Amy T. (Rice University) | Wong, Michael (Rice University) | Tomson, Mason B. (Rice University) | Tour, James M. (Rice University)
Polyvinyl alcohol functionalized oxidized carbon black efficiently carries a hydrophobic compound through a variety of oil-field rock types and releases the compound when the rock contains hydrocarbons.
The transport of small hydrophobic organic molecules through porous media has been studied for many years. In isolation, these hydrophobic molecules sorb very strongly to nearly all types of soil. However, it has been observed that these hydrophobic chemicals disperse more broadly in the environment than would be expected based on their strong affinity for binding to soil (Baker, 1986). One possible explanation for this behavior is that organic macromolecules, which possess amphiphilic characteristics, may sequester the hydrophobic small molecules and facilitate their transport by carrying them within the macromolecule (McCarthy, 1989; Enfield, 1988). Laboratory scale experiments have demonstrated this effect, with some cases, such as the use of ß-cyclodextrin, showing highly efficient transport of a variety of hydrophobic aromatic molecules through soil (Brussea, 1994; Magee, 1991). However, selective release of the transported cargo has not been reported and ß-cyclodextrin only forms 1:1 inclusion complexes with its hydrophobic cargo.
Carboxybetaine visco-elastic surfactants have been applied in acid diversion, matrix acidizing and fracturing treatments, in which high temperatures and low pH are usually involved. Amido-carboxybetaine surfactants are subject to hydrolysis under such conditions due to the existence of a peptide bond (-CO-NH-) in their molecules, leading to alteration of the rheological properties of the acid. The objective of this paper is to study the impact of hydrolysis at high temperatures on the apparent viscosity of carboxybetaine visco-elastic surfactant-based acids, and determine the mechanism of viscosity alterations by molecular dynamics (MD) simulations.
Surfactant-acid solutions with different compositions (surfactant concentration varied from 4 to 8 wt%) were incubated at 190°F for 1 to 6 hours. Solutions were then partially spent by CaCO3 until the sample pH was 4.5, and the apparent viscosity was measured using a HT/HP viscometer. To determine the mechanism for viscosity alteration on molecular level, MD simulations were carried out on spent surfactant-acid aqueous systems using the Materials Studio 5.0 Package.
It was found that short time hydrolysis at high temperatures (for example, 1 to 2 hours at 190°F) led to a significant increase in surfactant-acid viscosity. However, after long time incubation, phase separation occurred and the acid lost its viscosity. Simulation results showed that the viscosity alteration of amido-carboxybetaine surfactant-acid by hydrolysis at high temperatures may be due to different micellar structures formed by carboxybetaine and fatty acid soap, its hydrolysis product. The optimum molar ratio of amido-carboxybetaine and fatty acid soap was found to be nearly 3:1 from our simulations.
Our results indicate that hydrolysis at high temperatures has great impact on surfactant-acid rheological properties. Short time viscosity build-up and effective gel break-down can be achieved if surfactant-acid treatments are carefully designed; otherwise, unexpected viscosity reduction and phase separation may occur, which will affect the outcome of acid treatments.
Quillen, Todd R. (Chevron) | Wyatt, Jeff D. (Chevron Corp.) | Al-Dossari, Mohammed S. (Chevron) | Merritt, Steven Edward (Chevron Overseas Petroleum Inc.) | Davis, Andy (Geomega) | Sheffield, Jesse (Geomega) | Fahmy, Yasser (Chevron Environmental Management Company)
Over 380 hectares of evaporation pits were used to manage produced water required remediation in response to environmental master planning at the Wafra oil field. To facilitate closure of these impoundments, a risk-based cleanup was selected wherein the former pit areas were backfilled using the reclaimed contents which were temporarily stored as stockpiles after stabilization and sampling. A risk assessment conducted for the site identified 3.2% total petroleum hydrocarbon (TPH) as a cutoff protective of human health, however, to adhere to the precautionary principal, material containing 1 to 3.2% TPH (type B) was consigned to deeper areas of the former pits, capped with 1 m of <1% TPH material (type A), and overlain by a minimum 30 cm of clean sand to facilitate revegetation. This paper describes a novel, multi-year approach to streamlining the remediation of >2 million m3 of impacted sand in a complex environmental setting, while meeting stringent international risk guidelines.
Initially, laboratory analytical data from a stockpile boring program were correlated with field test-kit and color analyzer measurements to develop a simple field TPH measurement tool. Then statistical analysis coupled with computation of pit volumes and three-dimensional modeling of the site was used to describe the spatial distribution of types A and B in the stockpiles and a redistribution strategy developed to meet remedial goals.
Quantification of spatial TPH distribution in the five stockpiles allowed optimization of hauling distances to the pit locations, while use of real-time global positioning system (GPS) survey data of the stockpile reduction in conjunction with geographic information system (GIS) applications allowed for accurate calculation of volumes excavated and placed as backfill, facilitating contractor invoicing. The use of sophisticated computer technology as part of the overall project design streamlined engineering design, while the GIS methodology also tracked real-time progress and provided final documentation for the project.
Al-Muntasheri, Ghaithan A. (Saudi Aramco) | Sierra, Leopoldo (Halliburton Co.) | Garzon, Francisco Orlando (Saudi Aramco) | Lynn, Jack D. (Saudi Aramco) | Izquierdo, Guillermo Antonio (Halliburton Co.)
A horizontal hot deep gas well was not on production due to high water cut. The well had a bottom hole temperature of 300ºF (149ºC) and a bottom hole pressure of 7,000 psi. The well was completed into a carbonate reservoir with an average permeability ranging from 2 to 3 mD. It was completed with a 7 in liner at a measured depth (MD) of 13,611 ft. The openhole section extends from 13,611 to 16,456 ft. After the well completion operation, water was observed entering the openhole section at the toe at a depth of 14, 677 ft. The exact water producing zone was identified by the resistivity log run on the subject well. Therefore, a mechanical packer was set in the openhole section at 14,677 ft to isolate the water producing interval. The packer did not solve the problem. The water production continued to occur.
Due to their versatility, polymer gels were considered for remediating this problem and to revive the well. A gel system based on a low molecular weight polymer crosslinked with an organic crosslinker was considered. A serious challenge was the high temperature of the reservoir. The high temperature conditions imposed the use of a retarder to elongate the onset gelation time during the polymer gel placement. The available mixing waters in this field contained significant amounts of salts (a total dissolved solids content of 1,188 ppm). These solids caused compatibility problems upon contact with the commercially available retarder. Therefore, a new retarder was developed. The retarder was cost effective, efficient and compatible with the available saline mixing water. The retarder's placement was examined in porous media under conditions similar to those encountered in the field (55 minutes placement time). The gel did not show any injectivity problems indicating the efficient nature of the retarder. The initial recommended recipe of the gel showed syneresis due to the extra amount of the crosslinker suggested. This was addressed by reducing the crosslinker concentrations in the gel recipe.
The treatment utilized a preflush to displace the reservoir fluids around the wellbore and to cool down the near wellbore area. This helped reduce the near wellbore area temperature from 300 to 240ºF according to the temperature simulations. The gelant contained 250 gal/1000 gal of polymer with a 10 gal/1000 gal of crosslinker. After the gelant placement, the well was shutin for three days. Once opened, the well showed an increase in gas production by a factor of 7.7 with a water cut reduction of 42 %.
Asphaltene precipitation and deposition from oil reservoir fluids during production are serious problems for the oil industry, as it can cause plugging of reservoir formation, wellbore, tubing and production facilities. Kuwait Oil Company (KOC) is facing asphaltene deposition problems in the wellbore of some of the Marrat Jurassic reservoirs in West Kuwait (WK), South East Kuwait (SEK) and North Kuwait (NK). This has caused a reduction in production and shutting of some of the wells and a severe detrimental effect on the economics of oil recovery.
As part of a major strategic program for development of the master plan for Improved and Enhanced Oil Recovery (IOR/EOR) techniques for Kuwaiti reservoirs, two projects have been conducted by a joint team in Kuwait Institute for Scientific Research (KISR) and KOC to screen all the reservoirs with the available techniques by assessing incremental recovery. Miscible gas injection such as CO2 and Hydrocarbon techniques were recommended for more than 80% of the
light oil reservoir in Kuwait. Currently the Field development (FD) teams in KOC are planning further investigation and are conducting lab tests and simulation
studies to design the first pilot tests for CO2/HC injection for several of the selected reservoirs in NK, WK. Comprehensive laboratory testing, modeling
tuning and simulation preparation is required for this design study.
Any Oil production processes and the application of IOR & EOR can modify the flow and phase behavior of the reservoir fluids, and rock properties. These modifications could lead to asphaltene precipitation. Asphaltene deposition on formation is a serious problem, and it might occur during CO2/gas injection, and can cause porosity and permeability reduction in the reservoir, and plugging wellbore and piping in production facilities. In the planning of any gas injection IOR projects, the flocculation and deposition of asphaltene in porous media and their interaction with rock and fluid represent complex phenomena which need to be investigated under dynamic flowing conditions.
In this paper, a systematic approach for the investigation of Asphaltene problems in reservoirs during primary production, pressure depletion and IOR/EOR processes under gas injection processed will be presented. Some of the results of the initial laboratory studies on the characterization and phase behavior studies of typical crude oil samples from Kuwaiti reservoirs will be presented.
As the end of the era of easy oil production is approaching, various IOR/EOR technologies will be applied to matured reservoirs worldwide. Using these technologies, 60 % or more of the reservoir's original oil in place can be extracted, compared with only 20-40 % using primary and secondary recovery.
CO2 gas injection, chemical injections and thermal recovery techniques are the main approved technologies that are being applied in future developments during both secondary and tertiary stages of oil recovery. CO2 injection from industrial plants emission also provides another beneficial opportunity due to the added value of dealing with global warming and reducing Green House Gas (GHG) emission by CO2 sequestration and as storage oil/gas reservoirs.
The Marrat reservoir in Dharif field is a deep, sour, high pressure oil accumulation of Jurassic age containing light under-saturated oil of 36-380 API. The carbonate reservoir has a porosity range of 10-20% with permeability of 1-10 md. The field was put on production in 1989 through one well. Subsequently, 10 wells were added gradually developing the field. As of date, the field has produced about 12.5% of oil in place, lowering the reservoir pressure from 10,525 to 7,000 psi.
At present, oil production from the field is about 13,500 bbls/day. Due to low permeability, some wells produce with high drawdown approaching asphaltene onset pressure (AOP), estimated at 3,400 psi. This causes Asphaltene deposition in the tubing that requires cleaning to maintain the production level. The major challenges now are to produce the wells above AOP to avoid asphaltene precipitation in the wells or reservoir while sustaining the production level and maximizing recovery.
Hence, Full Field Model (FFM) for simulation studies was constructed and history-matched. Under depletion case, where the wells produce above AOP, field produced about 24% STOIIP. The water injection case shows significant increase in recovery to 40% STOIIP. Since no prior experience of water injection is available for such tight deep carbonate reservoirs in West Kuwait Fields, several key studies such as a) RCAL & SCAL b) Core flood Study c) Water Compatibility & Scale Prediction modeling d) Injectivity test, were carried out to address water injection feasibility.
The present paper shares the results of above studies which indicate that water injection is a viable option to maintain the reservoir pressure to produce the wells above AOP as well as to maximize recovery. Pilot water injection is planned through one well for which the area has been optimized using FFM. At present Pilot Water injector and source wells have been drilled and injection will be initiated with commissioning of surface facilities
Dharif field is NNE trending elongated anticlinal structure with faulted western limb. The Marrat reservoir in this field has developed in carbonate aggradational and progradational depositional setting. The field was discovered in 1988, put on production in 1989 and gradually developed with additional producers until 2004 (Fig-1). As of today, total 13 deep wells have been drilled in this field of which eleven are completed in the Marrat reservoir, while two are completed in a shallower Jurassic reservoir. The reservoir porosity ranges between 10-20 % while the average permeability is low, ranging between of 1-10 md with locally higher permeability of about 20 - 30 md in some layers. The average net reservoir thickness is about 200 ft and water saturation is less than 15 %. Initial oil water contact (OWC) was estimated to be 13,360 ft Subsea. The initial reservoir pressure was 10,525 psi at 13,200 ft SS (datum). The oil is under saturated with saturation pressure as 1,959 psi. Oil is light and the density is 36-380 API. The asphaltene onset pressure (AOP) is nearer to 3,400 psi, at a temperature of 2350 F.
Al-Marri, Salem Sml (Kuwait Institute for Scientific Research) | Alkafeef, Saad F. (College of Technological Studies) | Chetri, Hom B. (Kuwait Oil Company) | Al-Ghabdan, Asma'a (Kuwait Oil Company) | Al-Anzi, Ealian H.D. (Kuwait Oil Company)
Reservoir souring while water flooding North Kuwait reservoirs has been predicted by modeling studies in the past. One of Sabiriyah Mauddud wells showed up H2S as first indication of reservoir souring, which was an alarm bell for production facilities designed for only sweet crude. Surface/ Bottomhole fluid samples were required to confirm whether it is localized or reservoir-wide. In order to track reservoir souring and monitor on continuous basis, a process for tracking of reservoir souring annually was developed and initiated for the first time in 2006. Subsequently, this has been made part & parcel of fluid study requirements each year.
As sea water is being injected into traditionally sweet reservoir like Sabiriyah Mauddud, some degree of reservoir souring is expected due to Sulfate reducing bacterial (SRB) activity, as was projected happen sometime in 2005 in wells, needing monitoring/ mitigation actions. Expected H2S levels being very low (50-200 ppm), risk of loosing and not capturing these concentrations using conventional samplers/ bottles due to absorption/ reaction with the metallurgy of the samplers was felt, thus posing a challenge for obtaining a representative bottomhole sample for the analysis of H2S.
A comprehensive sampling program was made jointly by KOC & KISR, using the non-reactive internally coated samplers for capturing bottom hole samples; performing the onsite analysis, followed by immediate shipment to the local fluid analysis laboratory and conduct all necessary analysis with expert supervision & care.
Value was added to North Kuwait Water flood management by timely knowing the onset of reservoir souring. The analysis also led the way forward for the review of chemicals dosages; interventions needed in case of H2S occurrence; inputs to the future facilities and the requirements of further modeling studies.
Sabiriyah Mauddud, a super giant depletion drive oil reservoir in North Kuwait, is undergoing massive development efforts, with a planned enhancement in oil production through phased pattern water flood. The Phase1 development covers the crystal area of the structure, which is the focus for current development efforts through twelve number of inverted 9-spot water flood patterns.