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.
Gezeeri, Taher Mohd Nabil (Kuwait Oil Company) | Hamim, Ahmed Ibrahim (Kuwait oil Company) | Zereik, Rachad (Halliburton) | Hughes, Simon Nicholas (Halliburton Sperry-Sun Drilling Services) | Scheibe, Christian (Halliburton sperry sun drilling services)
The Upper Cretaceous Mishrif reservoir in Minagish field is currently being developed by Kuwait Oil Company (KOC) using a horizontal drilling program. The Mishrif reservoir is approximately 300 ft thick across the field, with an average net pay of 170 ft in the upper layers. The reservoir porosity varies from 15 to 30%, and permeability ranges from 0.001 to 17mD. The first Mishrif horizontal well was drilled from west to east in the northern block of Minagish field. The well appears to have penetrated several generations of faults and associated fractures (early northwest to southeast, intermediate northeast to southwest, and possible late northwest to southeast. The production rate has been poor (approximately 500 bbl oil per day). An evaluation of the image logs indicated that only two of the reservoir layers appear to be fractured, whereas other layers are muddy and devoid of fractures, even near faults. To address the structural and stratigraphic uncertainties of the Mishrif reservoir, a high-resolution elemental chemostratigraphy study was performed on cored wells prior to additional drilling. The study produced a robust elemental zonation primarily based on variations in CaO/MgO, CaO/Sr, and MgO/Sr (carbonate-related), SiO2/Al2O3 and Zr/TiO2 (detrital-related), and Br, S, Na2O, and Cl (diagenetic phases and/or formation waters). The study results were used to calibrate a portable laser-induced breakdown spectroscopy (LIBS) instrument, which was used for near real-time chemostratigraphy at the wellsite to assist in geosteering operations. The recent horizontal well penetrated a highly faulted section in Mishrif layer 2, with significant changes in dip related to faults. LIBS technology assisted in actively optimizing the well path in the porous limestone zone, only 5 to 10 ft thick, within this structurally complex regime. The distribution of possible fracture swarms and faults was reflected by abrupt changes in the geochemical profiles (MgO/CaO, S, [Ni+V+Fe2O3]/Al2O3, Na2O, and Cl). This well achieved a new record for the longest horizontal drain hole in Kuwait.
The Large Scale Steamflood Pilot (LSP) is a project aimed to determine the feasibility of economically steamflooding the Wafra First Eocene carbonate reservoir. The field is located in the Partitioned Neutral Zone, between Kuwait and Saudi Arabia. The reservoir is a dolomite, with 14-20*API oil. The LSP consists of sixteen inverted 5-spot injection patterns. A fully integrated workflow was matured to maximize the value of information provided by four full cores that were collected when drilling the LSP wells. Core work will support reservoir characterization and dynamic simulation, essential tools for project decision-making. High-level workflow consisted of the following phases: (i) define field, laboratory and office activities, (ii) identify and prioritize stakeholders, (iii) delineate project schedule and assign responsibilities. Coring and core
analysis for heavy oil involves short, mid and long term activities, that may require several years of planning and execution. Planning and frequent communication engaged core experts very early in the work process. Their input was used to shape the project, assuring reliable execution of dependent and independent tasks as work progressed. Synergies between subject matter experts were promoted, and proved to add value to the project. Due to the organizational efforts, the project schedule was not affected by personnel changes. Concerning lab measurements, the operator's heavy oil experts recommend Best Practices for the determination of relative permeability. Long equilibrium times, crude oil instabilities, and viscous fingering are challenges unique to heavy oil systems. Limited capability for such measurements exists in the industry. Heavy oil tests are not routine and should be carefully assessed. We hope that the integrated workflow proposed in this paper provides guidance to similar projects on planning and execution of heavy oil coring programs and analysis.
The Large Scale Steamflood Pilot (LSP) is the third in a series of staged tests conducted to validate the feasibility of applying the enhanced oil recovery technology of steamflooding to unlock the production potential of the heavy oil Eocene reservoir in the onshore Partitioned Neutral Zone (PNZ). Refer to Fig. 1 for the PNZ location. Previous tests included the Small Scale Steamflood Test (SST), which was successfully completed in 2008, and simple steam stimulation testing, conducted in the
late 1990s. The LSP consists of sixteen inverted 5-spot injection patterns. The project is expected to lead to full-field steamflooding of the First Eocene reservoir, marking the first commercial application of a conventional steamflood in a carbonate reservoir anywhere in the world.
The First Eocene is the shallowest reservoir at Wafra field. Average depth to the top of the reservoir is about 1,000 feet. The stratigraphic interval averages 750 feet thick with a gross average porosity of 35% based on well log and core data, and a gross average permeability of 250 md based on core plug measurements. Based on current field practice a porosity cutoff of 35% is used to define net reservoir. The average porosity in the net reservoir is 43% and the net average permeability is about 280 md. The reservoir was discovered in 1954. Full field development and production commenced in 1956. Current oil cumulative from the reservoir is over 300 MMBO. Oil production exceeds 25,000 BOPD of 14-20 ºAPI high-sulfur oil. The First Eocene is a depletion drive reservoir, with partial solution gas drive and limited aquifer support. The aquifer support is not sufficient to maintain the reservoir pressure at current production rate.
A fully integrated workflow was matured to maximize the value of information provided by four LSP cored wells. Core work will support reservoir characterization and dynamic simulation, essential tools for project decision-making. The purpose of this paper is to describe the approach that was followed to maximize the value of heavy oil core analysis and support the LSP development with appropriate petrophysical data.