bluuebunny/crossref_metadata_2025 huggingface dataset:
The Mechanism and Application of MEOR by Brevibacillus Brevis and Bacillus Cereus in Daqing Oilfield
Authors: Hou Z. , Wu X. , Wang Z. , Han P. , Wang Y. , Xu Y. , Jin R.
Published: December 2007

The mechanism of petroleum hydrocarbon degradation by the selected bacteria Brevibacillus brevis and Bacillus cereus is studied based on the metabolite analysis. The result shows that bio-oxidation processes, especially those called unconventional subterminal oxidation, terminal and double-terminal oxidation, are the main pathway by which the bacteria will convert petroleum hydrocarbons into fatty monoacids, hydroxyl fatty acids and dicarboxylic acids. This, for the first time, makes an important correction to the prevailing opinion which says that long-chain hydrocarbon molecules can be degraded into short-chain hydrocarbon molecules instead of acid compounds. The study explains how the bacteria ingest petroleum hydrocarbons as well as the correlation between ingestion modes and the active substances present in crude oil. The pathway to produce bio-surfactants and the correlation between produced bio-surfactants and oil metabolism are also discussed in this paper.

From 2002 to 2004, Brevibacillus brevis and Bacillus cereus were applied in the microbial huff and puff as well as the Microbial enhanced waterflood test in Daqing excessively low permeability (1.0md-25md) reservoir. After bacteria injection, 44 among the 60 huff and puff wells shows a significant oil production response—the accumulative oil increment reaches 6012 tons and the input-output ratio amounts to 1: 6. The Microbial enhanced waterflood test carried out in June 2004 also provides a satisfying result. After the injection of bacteria, the pressure in the two water injectors decreased more than 2MPa, which results in an injection capacity increase. In late 2004, the fluid production of the 5 producers (the total number is 8) is increased from 29.5 tons per day (before bacteria injection) to 44.4 tons per day, and the corresponding oil production is increased from 20.8 tons per day (before bacteria injection) to 36.9 tons per day. These make MEOR a very promising oil recovery method in Daqing Oilfield.
Water Flooding Efficiency in a Scenario of Multiple Induced Fractures, an Applied Geomechanical Study
Authors: Chavez J. C. , Carruthers J. , McCurdy P.
Published: December 2007

Understanding and predicting multiple fracture propagation behaviour whilst injecting water in the layered reservoir of Field A, offshore Nigeria, presents several major challenges.

The water flood efficiency will be affected by the behaviour of each independent fracture during the injection process. For this reason an accurate estimation of the behaviour of each individual fracture and their interdependence are essential for field development.

The principle objective of the study was to find the main factors that controlled the multiple fracture growth behaviour using a 3D fracture simulation model. A water injection well was planned in a reservoir with 5 moderate to high permeability sand layers varying from 6 to 25 feet in true vertical thickness. A further consideration was that the sand layers in the reservoir had depleted from 2600 psi to 1900 psi. A comprehensive lithological and geomechanical model of the reservoir section was constructed for simulating the injection process. As a mixture of seawater and formation water was planned for injection possible chemical effects were also considered in the study. The 3D simulation model of multiple fracture propagation considered thermal and pore pressure effects. In addition, reservoir pressure depletion and particle plugging were also considered.

The behaviour of each individual fracture was shown to be interdependent on the other fractures in the model. The results of the simulations demonstrated that over the first 5 years of planned water injection, the behaviour of the fractures was mainly dependant on the pressure depletion effects at the time of water injection and particle plugging. Critically, the depletion effects were the decisive element in fracture containment i.e. to guarantee vertical growth into only the selected sand sequences. Some scenarios that were modelled showed that for the planned injection flow rates, fracture containment was not possible after one year of injection. However, in these cases, if the injection rate was reduced by around 20% for a limited period, the fracture growth could be controlled. Full rates could be resumed after this reduced injection period. The introduction of such an injection flow rate control (IFC) during the injection period would then allow the fracture containment and water flood confinement into the selected reservoir sequence.

Understanding the variables that influence multiple fracture behaviour allows timely decisions on surface equipment requirements. In addition the operational conditions associated with the injection process are defined. The injection strategy can then be targeted to promote an optimum water flood profile and water placement into only the selected sand intervals.

It is through the process of modelling the multiple fracture interaction and behaviour that the water injection efficiency can be optimised.
Proper Clean Up and Improved Re-Acidization Quadruples Productivity Index in a HP-HT Horizontal Well Heavily Damaged With High-Weight Mud
Authors: Reji E. C. , Al-Medhadi F. , Mater M. B. A. , Stretch T. , Ali A. , Jassim M.
Published: December 2007

The re-acidization of HP-HT horizontal oil well Umm Guddair XXX in Kuwait resulted in a productivity index four times what was seen after the initial acidization. This astounding improvement in the results can be attributed to better acidization through thorough cleaning of the horizontal section prior to the 2nd stimulation, as well as placing the acid in stages and introducing a suitable diverting agent.
High-Permeability Carbonate Zones (Super-K) in Ghawar Field (Saudi Arabia): Identified, Characterized, and Evaluated for Gel Treatments
Authors: Al-Dhafeeri A. M. , Seright R. S. , Nasr-El-Din H. A. , Sydansk R. D.
Published: December 2007

Super-k (carbonate zones of extremely high permeability) can significantly enhance recovery per well in the Ghawar Field. These zones present a challenge at the onset of normal water arrival as the water contribution from these zones dominates the flow in the wellbore—causing either high water-cut or water loading. As a component of the common practices in Ghawar, water shut-off techniques such as the one described in this paper present an effective mechanism to manage water production. This research project has three objectives. The first objective is to identify and characterize super-k zones. The second objective is to identify chemical blocking agents that can be placed in super-k zones without reducing hydrocarbon productivity. The third objective is to identify an effective technique to optimize the size and the placement of the chemical blocking agents.

Concerning disproportionate permeability reduction (DPR), gelant treatments, that rely on the ability of the gels to be placed in the rock matrix adjacent to the fractures and to reduce permeability to water much more than that to hydrocarbons (DPR in the rock matrix); have more significant potential than does application of DPR in the fracture. A high residual resistance factor to oil in the fracture may shut-off oil.

Distances of gelant penetration can be predicted by knowing the pressure drop and controlling the gelation time. Gel properties for a strong gel that reduces permeability to water as a function of polymer concentrations can also be predicted. If pressure drawdown is held constant before and after a treatment, calculations suggest that relatively small gelant volumes may be most cost-effective in our case. The cost of water treatment, the initial water production rate, the oil residual resistance factor, and the pressure drawdown have strong effects on the economic benefits derived from this approach.
Gulf of Mexico Shelf Deep Ultra HPHT Completions - Current Technology Gaps
Authors: Hahn Dennis , Atkins Michael , Russell Jos , Pearson Bob
Published: December 2007

Numerous operating companies are pursuing new and much deeper geologic horizons on the Gulf of Mexico continental shelf. This is a logical expansion of a geographic area with a very mature and well established surface infrastructure. However, as the well depths increase, the wellbore construction and well production operations become much more challenging because ultra-high pressures and high temperatures - HPHT (e.g. 25,000+psi and 450+°F) will then need to be handled and/or managed. The industry is probably able to safely drill these more extreme wells but there are some significant well completion technology gaps that require design and development. The most cost efficient approach to bridge these gaps may be for several companies to collaboratively share in the costs to develop the appropriate equipment for these applications.

This paper demonstrates the need to enhance the industry's capability to actually begin production from these deep ultra HPHT wellbores. The numerous areas that require increased completion capability will be presented in this paper. The production tubulars (casing and tubing) will be a major cost driver as designs will need to address temperature deration of strength, geometric complexity to achieve adequate bore and clearances, corrosion and environmental cracking. Risk analyses and testing will dictate metallurgy, pressure containment, connection capability under compression and bending, and benefits and reliability of cementing. Production packers, subsurface safety valves, and flow control nipples/plugs appear to be the nearest to implementation, but some design and qualification issues still need to be resolved. Current perforating technologies are reaching their limits at temperatures exceeding 450°F, thus require significant attention in their specific application and a quality assurance/quality control (QA/QC) program. The major hurtle for fully rated completion blowout preventors (BOP's) and trees will be the need to redesign the valve stem sealing mechanisms. Finally, both intervention and contingency possibilities, like slickline, pumping services, stimulation, snubbing, etc., are important situations that require additional enhancements to currently available technologies.
Design and Qualification Challenges for Mudline Well Control Equipment Intended for HPHT Service
Authors: Berckenhoff Mike , Wendt David
Published: December 2007

In recent years there has been an increasing interest in the development of high pressure/high temperature (HPHT) prospects, requiring enhanced equipment designs for operation in this environment. The more severe HPHT wellbore conditions, often defined as any reservoir pressure exceeding 10,000 psi and temperature above 300°F1, necessitate changes in design criteria and operational procedures. The resulting requirements may range from simple upgrades of existing designs to complete redesigns with new materials and geometries. This paper will discuss some of the additional types of analysis and testing required to qualify mudline well control equipment for these more severe conditions. Additionally, changes to operating procedures for this type of equipment will be presented.
Stochastic Kick Load Modeling
Authors: Mason Stan , Chandrasekhar Sharat
Published: December 2007

As our industry starts to plan and drill ultra-deep wells, we are beginning to find that the established methods for calculating maximum anticipated surface pressure (MCP) produce loads that exceed the strength of many conventional API weights and grades. Addressing this situation, regulators have entertained modifications to the methods by which we calculate MCP. Although this is becoming a common practice, the approach is flawed in that it is arbitrary in nature and only partially considers the real-world limits placed on our drilling system. Furthermore, no method used to date addresses the fluid miscibility issues that we encounter with the oil-based muds used to drill these wells.

A stochastic kick load model specifically developed to consider the entire physical system in which a kick is initiated and dealt with, offers a higher level of confidence than any arbitrary method can. After a review of two commonly used MCP calculation methods, this paper will describe, in detail, one such model, the inputs required, the assumptions used and the outputs generated. This paper concludes with a discussion of the challenges facing those who wish to implement such an approach.
The Qualification of C110-High Strength Sour Service Casing–A Statistical Approach to Evaluating Material Data Across A Single Production Heat Lot
Authors: Urband Bruce E. , Garrison Brian , Prideco Grant , Cernocky Paul , Tallin Andy , Sponseller David L.
Published: December 2007

Designing casing for ultra-high pressure, high temperature (HPHT), hydrogen sulfide bearing wells creates a need to characterize the sour performance uncertainty (scatter) of higher strength, low alloy carbon steels casing such as grade C110. Casing properties generally vary by: source mill, degree of hot working, product type (seamless pipe vs. electric resistance welded pipe), steel chemistry, size and wall thickness, particular heat lot, particular joint of pipe, and location on the joint of pipe. Measured properties also can vary according to the number of and choice of laboratories doing the testing. All of these factors can contribute to the perceived scatter in the sour material properties associated with the product. In order to determine the mean and scatter of sour properties which characterize grade C110 casing and create a benchmark for the minimum possible scatter that can be achieved in a production order at a level practical for well design, Shell International E&P and Grant Prideco-TCA jointly generated a population of sour property test data across a single, commercially produced, heat lot of casing and using the services of a single NACE testing laboratory, OMNI Metals Laboratory. Grade C110 is a high strength sour service material, which is currently being considered for standardization by the American Petroleum Institute (API).

This paper details the results of sixty-six NACE Method D (DCB) tests and seven NACE Method A (tensile) tests conducted across one single, commercial production heat lot of Grant Prideco-TCA grade C110 low alloy carbon steel. All tests were conducted at OMNI Metals Laboratory. The data conceptually represent the tightest possible practical spread of sour material properties since all the data were obtained from a single heat lot of pipe sampled every 10th pipe-end and along a joint of pipe within the single lot. Hardness was found to be remarkably uniform. Results of the data are correlated in terms of model uncertainty for KISSC vs. hardness. The paper also presents a correlation between hardness measured on pipe-ends and hardness measured on the corresponding NACE specimens. Tests were performed in standard NACE A Solution and at milder conditions. For this grade material, the mean DCB results were significantly higher than the industry trend and the scatter was unusually low indicating high product consistency across the heat. Results quantify the impact of reducing the H2S concentration to a fit-for-purpose environment based on NACE Method D test data.
Metallurgical Limits to Increasing Tubular Strength While Maintaining SSC Resistance
Authors: Craig Bruce
Published: December 2007

There is a demand in the petroleum industry for high strength casing and tubing steels that have yield strengths exceeding 110,000 psi and yet have acceptable resistance to sulfide stress cracking (SSC). However, contrary to expectations and the desire to simply enhance current steel compositions and processing, there are no easy means to achieve increased strength and maintain or increase the SSC resistance at the same time. Only small incremental increases in performance can be achieved with current conventional tubular manufacturing and the limit of these increases has been reached. This paper will present the factors that increase the SSC resistance of conventional high strength steel tubulars and their limits which have been exhausted at this time. Possible ways forward to meet the challenge of high strength tubulars with good SSC resistance for HPHT wells will be discussed.
Premium Connection Design, Testing, and Installation for HPHT Sour Wells
Authors: Bradley A. B. , Nagasaku S. , Verger E.
Published: December 2007

Drilling and completing wells deeper, and in HPHT sour environments, magnifies the importance of having reliable threaded casing and tubing connections. High pressure/high temperature wells present many critical challenges for threaded tubular connections. Through design, proof testing, and installation, premium connections are meeting these requirements in a number of ways. With coupling stock for thick walled tubulars and sour service environments often being the limiting factor as the pipe wall increases, integral connections, and threaded and coupled designs with pin to pin contact allow the use of production casing over one inch in wall thickness. The incorporation of resilient seals into threaded and coupled connections can offer secondary back-up seals to the primary metal to metal seals.

Premium connection designs are often required to be validated or pass a qualification test program before acceptance by the users. Two fundamental approaches exist for qualification testing; product line testing and project specific testing. Product line testing is used to "qualify" a range of dimensions and wall thickness within a given design and is often accompanied by Finite Element Analysis (FEA). Project specific testing is used for very critical applications and when the connection designs are tailored to meet specific requirements. The ISO 136791 test procedure is most commonly used as the basis for qualification testing although "modified" ISO and other qualification test procedures are also used.

The design and qualification of HPHT connections determine that the connections are fit for purpose and that they provide reliability for HPHT well applications. The installation process is also a critical issue in the successful drilling and completion of such wells. Computer controlled make-ups, low stress or non-marking dies in handling equipment and even the application of the proper thread compound and quantity can be critical components in the successful completion of HPHT sour wells.
The Effect of Radial Loads on Connection Design in Ultra High Pressure Wells
Authors: Gonzalez Manuel E. , Wu Jiang , Hensley J. Rodney , Chandler R. Brett , Muradov Andrei , Jellison Michael J.
Published: December 2007

The industry has been designing casing and tubing for wells for many years by using the expected operational loads to calculate the triaxial stresses on the tubular walls. Part of the triaxial stresses is the radial component. In most cases pressures less than 15,000 psi, the radial triaxial component is not a major factor in the stress on the tubing wall. However, on higher pressure wells (above 15,000 psi) this radial component becomes significant in the design of the tubing and casing. During the conceptual design of ChevronTexaco's deepwater Tahiti project, several wells were projected to depths of anywhere from 26,000' to over 30,000' TVD. Under certain operational loads (such as fracturing or perforating), the pressures at the deeper horizons can exceed more than 25,000 psi (both inside and outside the tubing). We then asked ourselves a question, "If the radial load becomes significant on the actual tubing wall, what would the same radial load do to our connections"? It is very important to point out that you can have no differential pressure across a connection and still have intense radial loads.
Corrosion and Environmental Cracking Evaluation of High Density Brines for Use in HPHT Fields
Authors: Piccolo Eugenio Lo , Scoppio Lucrezia , Nice Perry Ian
Published: December 2007

In high pressure high temperature (HPHT) gas condensate wells the use of high density brines is required to ensure safe well operations during both well drilling and completion phases.

This investigation studied the corrosion and environmental cracking behaviour of several high density brines in simulated HPHT conditions.

The tested materials were low alloy steel grades P-110 and C-110, supermartensitic stainless steel (S13Cr) grade 110 ksi, duplex stainless steel, galvanized carbon steel wireline, duplex stainless steel wireline, superaustenitic stainless steel (N08535) and alloy 718. These materials were tested as single corrosion coupons, c-rings and four point bent beam specimens.

A test program was embarked, selecting experimental conditions representative of future HPHT Field developments in the Norwegian Continental Shelf.

The test results showed that S13Cr and duplex stainless steel suffered SCC failure in CaCl2 and CaCl2+CaBr2 brines at HPHT.

The effect of corrosion inhibitor with these brines was variable, but acceptable to low alloy steels.

It was also found that alloy 718 suffered a significant loss in ductility due to hydrogen embrittlement when exposed to caesium formate. But this did not result in cracking failures under the static loaded test conditions.

S13Cr suffered both general and superficial pitting corrosion with evidence of initiation of SCC associated with the pits when exposed to caesium formate.
Updated Design Methods for HPHT Equipment
Authors: Young Kenneth , Alexander Chris , Biel Richard , Shanks Earl
Published: December 2007

Drilling industry technology is advancing rapidly. Drillers are encountering downhole pressures over 20,000 psi and temperatures over 450°F. These high pressure high temperature (HPHT) conditions require drilling and completion equipment that is beyond the scope of today's API specifications.

API specifications 6A1, 16A2, 16C3, and 17D4 address the design and design verification methods for drilling equipment. These specifications currently reference the ASME Boiler and Pressure Vessel Code, Section VIII, Division 25 (ASME VIII-2) as one of the primary design verification methodologies. API specifications first referenced ASME VIII-2 as a design verification methodology nearly 20 years ago, because it was the best available at that time. This is called the " ASME Method".

The ASME Section VIII, Division 36 (ASME VIII-3) was developed to give the requirements for the construction of high pressure vessels. ASME VIII-3 was first issued in 1997 and is intended to be used in place of ASME VIII-2 for high pressure vessels, generally in excess of 10,000 psi.

The design of drilling and completion equipment should be done using first principles. The authors propose that the designs for 15,000 psi or higher service should be verified using the rules from ASME VIII-3. A significant difference between the two design verification methods is that the user specifies the loading criteria for the performance-based ASME VIII-3. ASME VIII-3 requires cyclic load (fatigue or fracture mechanics) analysis and has limitations in materials, fabrication and inspections, and testing requirements that specifically apply to thick-walled pressure vessels.

This paper discusses how the performance-based code methods of ASME VIII-3 can be integrated into API specifications for HPHT drilling and completion equipment.
Completion Optimization: Equipment & Material Qualification
Authors: Harris David , McGee Kerr , Frick John , Lane Bryan , Schwind Brian
Published: December 2007

Background

Engineering of completions programs that are reliable and cost effective is a fundamental responsibility of the drilling and completion community. Reliability methods for HPHT and critical well design are the most effective means of controlling schedule, cost, performance, and risk, which combine to define Life Cycle Cost (please refer to Figure 1). Optimization requires mechanical integrity while maximizing flow capacity of the system, thereby eliminating lost production and workover costs. Deep well costs can be among the greatest of the industry.

Reliability methods are common in industry and have seen increasing application in Exploration and Production. Reliability methods are not merely concerned with quantifying risk-rather the ultimate goal is production optimization with a robust system. System analysis, operating environment evaluation, component assessment, and data management are required in a reliability program and in optimized stochastic modeling. Following a discussion regarding production system design optimization the topics of material and equipment qualification will be presented. Drilling and completion optimization involves qualification of design (often through variability assessments and worst case analysis), Manufacturing (typically suppliers, material, and component qualification), assembly (which may include FAT1 and qualified rig procedures), and operations (that is operating within design limits).

Production system optimization addresses the four principal sources of failure shown in Figure 2. An integrated team is initially applied to optimize the completion program considering these four viewpoints, and then the team efficiently and cost-effectively executes the plan with specialists. Net present value of risked production and cost are used in optimization.
Gas Injection Feasibility Study of the Baram Delta Fields, Malaysia
Authors: Zain A. N. M. , Sudirman S. , Valdez R , Doe P. H. , Ray F. , Chai C. F.
Published: December 2007

A joint gas injection feasibility study by Shell International E&P Inc., PETRONAS and PETRONAS Carigali Sdn. Bhd. has been conducted for the Baram Delta Operation (BDO) fields, offshore Sarawak, Malaysia. The goal of the study was to design a robust pilot project to evaluate and prove the commercial viability of basin wide gas injection. The study consists of several phases, the first of which, and the focus of this paper, is to conduct a screening study to estimate EOR potential and select a gas injection pilot location. The total EOR potential from initial screening was estimated at 200+ MMSTB from six of the nine BDO fields. Building prototype static and dynamic models of the top five ranking EOR targets further refined these opportunities.

To enable screening and ranking of these targets, a spreadsheet based tool was constructed, which allows for rapid re-screening of reservoirs based on starting assumptions. The tool developed, BDO EOR Screening Tool (BEST), is based on several subsurface and surface criteria. The design of the tool allowed for screening of the total EOR potential and to determine the optimal pilot location. The screening required both immiscible and miscible gas injection potential to be estimated.

The top five candidates, based primarily on EOR potential, were modeled and the potential verified using reservoir simulation. The fully miscible injection cases, Baram field as an example, showed similar results to screening estimates; however, the near miscible and immiscible cases at West Lutong and Tukau fields respectively showed a lower potential. Ultimately, the West Lutong M/N reservoir was chosen as the gas flood pilot location for the following reasons: (1) large EOR potential in the M/N and K/L reservoirs, (2) minimum miscibility pressure (MMP) is at or near current reservoir pressure, (3) depositional environment analogous to several other reservoirs in BDO, and (4) considered one of three large targets required to implement large scale gas flooding in BDO.

This paper presents the methodology used in the screening of 1,000+ reservoirs and the unique features employed to develop representative prototype models using analogue field data.
Integration of New Open Hole Zonal Isolation Technology Contributes to Improved Reserve Recovery and Revision in Industry Best Practices
Authors: Henriksen K. H. , Augustine J. , Wood E.
Published: December 2007

This paper discusses developments in horizontal well completion practices. During recent years, the pursuit of screen based open hole completions with zonal isolation in deviated and horizontal wells has fostered the development of new technology, new applications, and processes to improve recovery of oil and gas. Based on case histories, computer simulations and laboratory testing, this paper describes recent findings which have lead to revisions in completion design and operating best practices.
Microscopic Rock Characterization and Influence of Slug Size on Oil Recovery by CO2 Miscible Flooding in Carbonate Oil Reservoir
Authors: Shedid S. A. , Almehaideb R. A. , Zekri A. Y.
Published: December 2007

Carbon Dioxide (CO2) has been recognized as a preferred miscible solvent for Enhanced Oil Recovery (EOR) methods. Miscible flooding by CO2 has proven its positive effectiveness through numerous laboratory and field projects. The main goals of this study are to provide microscopic reservoir rock characterization, and optimize the selection and the effect of CO2 slug size to be applied for carbonate oil field, U. A. E., on oil recovery by CO2 miscible flooding.

Scanning Electron Microscope (SEM) is used to provide accurate description of the reservoir rock surface topography. The SEM is used to attain the pore size distribution of the rock. Energy Dispersive X-Ray Spectrometer (EDS) and Inductively Coupled Plasma (ICP) are applied for detailed accurate analysis of elements constituting the rock.

Five flood experiments were performed to achieve the goals of this study. The first experiment was carried out using continuous CO2 flooding. Other three experiments used different CO2 slug sizes of 0.15, 0.30, and 0.45 hydrocarbon pore volume and chased by actual reservoir brine. The fourth experiment was carried out to evaluate the performance of waterflooding. All experiments were performed using actual crude oil injected into actual reservoir rock samples of almost 23 cm length and 10 cm diameter. These samples were saturated at initial-oil-in-place condition and then subjected to water and/or CO2 floodings. The minimum miscibility pressure (MMP) was calculated to be 3,700 psia using current correlations from literature. To secure good miscibility condition, all experiments were conducted under injection pressure of 4,200 psia and at 250 °F similar to the reservoir condition.

The results indicated that water flooding recovered 66 % IOIP and a continuous CO2 miscible flood produced 96 % IOIP. Furthermore, the increase of slug size increases oil recovery by CO2 miscible flooding, but the slug size of 0.15 HCPV is recommended since the increment in oil recovery using larger slugs does not represent significant addition to the oil recovery in comparison to applied smaller slug sizes.
Field Experiences in Application of a Novel Relative Permeability Modifier Gel in North Sea Operations
Authors: Wylde J. J. , Williams G. D. , Shields C.
Published: December 2007

Proposal

Over a dozen successive selective water shut off treatments (SWSO) have been performed on an individual North Sea field. The target wells were vertical, cased, perforated producers in a mature, high scale potential asset in the UKCS. Reservoir temperatures were in excess of 121°C and permeability ranged from 100 – 1000 mD. Mention is also given to several other treatments performed in this mature field on wells with water rates up to 16,500 bwpd.

Treatments were generally bullheaded as part of a scale inhibitor squeeze intervention, being contained in the final portion of the over flush. Results were all positive and in one case reduced water production by up to 60%. Furthermore, oil production was stimulated by up to 250%. The non-hazardous, low concentration chemical treatments were developed for pumping from the surface to reduce water production without affecting hydrocarbon production. It is more generally applicable than previous SWSO systems as it can be applied from ambient temperatures up to 130°C and 20mD – 16 D.

This paper details the treatment design and pre-qualification experiments to a variety of field applications of a novel relative permeability modifier gel. Details are given regarding the pumping schedule, treatment well test data, and lessons learnt from the operations.
Methodology for Miscible Gas Injection EOR Screening
Authors: Teletzke G. F. , Patel P. D. , Chen A. L.
Published: December 2007

Miscible gas injection is the most widely applied light oil enhanced oil recovery (EOR) process. A methodology, based on well-established physical principles, has been developed for estimating the conditions under which gas will be miscible with oil. The methodology enables rapid screening of a range of potential gas injectants (such as CO2, enriched hydrocarbon gas, N2, or H2S) through the use of readily available gas and oil properties. The methodology has been applied to numerous reservoirs worldwide. An overview of the methodology is provided along with an illustration of its application to screening of gas injection EOR for the Malay Basin.

The methodology makes use of a correlation1 that can be used to rapidly estimate miscible or near-miscible residual oil saturation, Sorm, minimum miscibility pressure (MMP), or minimum miscibility enrichment (MME) for a wide range of injected gases, crude oils, temperature and pressure conditions. The correlation is based on representation of the physical and chemical properties of the crude oil and injected gas through Hildebrand solubility parameters.

Thirty-four offshore reservoirs operated by either ExxonMobil Exploration and Production Malaysia Inc. (EMEPMI) or production sharing contract (PSC) partners were screened for gas injection EOR. Potential injection gases included pure CO2, CO2 diluted with methane, field separator gas, CO2 enriched with LPG, and separator gas enriched with LPG. A spreadsheet was created to facilitate calculation of MMP or MME using the solubility parameter correlation for a large number of reservoirs and potential injection gases. The correlation was useful for ranking reservoirs and potential injectants with respect to gas injection EOR potential and identifying which reservoirs to carry forward for in-depth laboratory and simulation evaluation.

In general, the predictions of the correlation compare reasonably with the more costly experimental data obtained in subsequent detailed evaluation.
Optimizing the Blowdown of Wizard Lake
Authors: Cook P. G.
Published: December 2007

The Wizard Lake D3 A pool went to blowdown in 2003, after achieving 86 % oil recovery from a vertical hydrocarbon miscible flood scheme. This paper describes some of the optimizations leading up to blowdown to increase gas sales and, in the initial stages of blowdown, to increase oil sales. A novel enhanced gas recovery scheme is also discussed, in which aquifer influx is diverted to another depleted pool through a horizontal well.
Solids Control and Waste Management for SAGD
Authors: Richards M. , Monkman B. , Comeau P. , Grant J.
Published: December 2007

The need to drill wells quickly and efficiently has challenged traditional thinking for solids control equipment, disposal services and fluids management practices in Steam Assisted Gravity Drainage (SAGD) drilling operations. Effective control of drilled solids and proper waste treatment are combined into an integrated fluids management program to address the challenges. Simultaneously, proper management of drilling wastes to meet more stringent environmental compliance must be addressed and coordinated amongst all parties.

Current practices address these needs, but have evolved in tandem with other aspects of drilling operations to suit the particulars of SAGD operations. Today's practices will also evolve as technologies advance; the evaluative philosophy and proper project management however remain an integral part of the process itself, and naturally foster future improvements which in-turn reduce risk both financially and environmentally.
High Mobility Ratio Water Flood Performance Prediction: Challenges and New Insights
Authors: Kumar M. , Hoang V. , Satik C. , Rojas D. H.
Published: December 2007

This paper presents results of a comprehensive study to improve our understanding of High Mobility Ratio Water Flood (HMRWF) and to improve its performance prediction. Published data on heavy oil water injection field projects are limited. Several successful HMRWF projects have been reported, and they show significant oil recovery at high water cut. However, the range of reported recovery is large – waterflood recoveries of ~ 1-2% to 20% OOIP have been reported for similar reservoirs. Higher viscosities result in lower recovery

Mechanistic study using fine-scale simulations show that viscosity (or mobility) ratio primarily controls oil recovery response, and that the recovery is lower at higher viscosity ratios. Further, viscous fingers dominate high viscosity ratio floods, and mobile water can significantly reduce recovery. Field-scale simulation results indicate that heterogeneity plays a more important role for a HMRWF (than conventional waterfloods). The amount of primary production prior to the start of the waterflood has a larger effect on incremental oil recovery for high mobility ratio floods. Further, highly-correlated, thin, thief zones reduce recovery of HMRWF more severely, and rock wettability (relative permeabilties) strongly influences oil recovery. These results indicate that accurate viscosity and relative permeability measurements are essential for a reliable performance prediction.
New Developments in Streamflood Modeling
Authors: Kumar M. , Satik C. , Hoang V.
Published: December 2007

Using recent results from fine-scale, multi-pattern, geostatistical models of the Kern River field, California, this paper reviews key issues related to steamflood modeling and shows that fine-grid models depict the near-vertical steam override, and corroborates that heavy oil steamflooding is not a displacement process; rather the oil drains by gravity. Further, models with unconfined boundaries result in steam zone pressures similar to those observed in field. Including the common operating practice of cyclic steaming of producers at early time reduces pressures and accelerates steam breakthrough time and recovery.

Furthermore, pattern element and single sand models used in many previous studies are not sufficient to explain observed field performance, and that larger, heterogeneous model give more realistic recovery predictions. Discontinuous shales allow significant drainage to occur from the upper to the lower sands. Consequently, the upper zones may contain less reserve than expected and the lower zones can give apparent high recovery. Use of parallel models showed significant speed up over serial models allowing significantly larger models to be run in a reasonable time. Apparent higher speed up is gained for larger models.

The paper demonstrates that the current improvements make larger-scale modeling of steamflood projects viable compared with what was possible earlier and that a realistic forecast of steamflood performance is attained when the necessary details are included in the model.
Case History: First Commercial Illinois Coalbed Methane Project Commences through a Structured Resource Evaluation Plan
Authors: Rodvelt G. D. , Oestreich R. G.
Published: December 2007

The Illinois Basin has an estimated 21 Tcf of natural gas trapped in the coal seams that cover Illinois and Indiana. A Saline County, Illinois coalbed methane (CBM) project has been selling gas into pipelines. The authors describe the evaluation plan used to set up a pilot project and proceed into field development.

A step-wise program of gathering reservoir data preceded a successful pilot program where gas-content information, thickness maps, and adsorption isotherms were acquired and integrated into a Davis and Dekoven drilling program. Gas producibility was established from a five-spot pilot (five wells drilled in a field to help operators evaluate the CBM commercial potential of the field) leading to a 30-well development program in 2004. Well information presented includes spacing, orientation, reservoir parameters, and completion designs. The description of a remote monitoring system that reduces labor costs and provides real-time data via the Internet is also provided. Future expansion plans include additional testing and zonal completions.
Post-Yield Material Characterization for Thermal Well Design
Authors: Kaiser T.
Published: December 2007

Conventional material specifications and test methodologies were developed to support load-based designs in which inelastic deformations are relatively small and yield strength is the primary material factor governing design. However, in strain-based designs where substantial portions of the structure soften under post-yield deformation, more detailed characterization of the post-yield material behavior is required. This paper presents a framework for describing the post-yield properties of metals, including strain-rate dependence of yield strength, a testing methodology for measuring post-yield strength in terms of strain and strain rate, and an analytical basis for extrapolating measured properties to static conditions for strain-based design and quality assurance.
3D Geomodelling and Flow Simulation of the Late Devonian Bakken Formation in South-Central Saskatchewan - Case Study: Smiley Buffalo Heavy Oil Waterflood
Authors: Mohr R. , Estrada C. A. , Norrena K.
Published: December 2007

A sound geological model, a consistent geocellular model, and flow simulation are all critical components to successful optimization of a heavy oil waterflood project. Despite the availability of a sound geologic model, high quality seismic and abundant core, log, and production data, optimization of the waterflood project at the Smiley Buffalo field in south-central Saskatchewan held many challenges

The primary reservoir at Smiley is the middle Bakken sandstone which was deposited as offshore sand ridges in late Devonian to early Mississippian time. The reservoir structure has been subjected to post-depositional solutioning of the underlying Torquay Formation and karstification which causes reservoir breaks, fracture networks, and irregularities in the saturation functions. These features have important effects on reservoir performance. The geologic model and seismic information were used to construct a consistent structural model. A facies classification model was built with fuzzy logic which used the core and log data as well as the geologic model. Sequential indicator simulation was used to populate the structural model with facies information, and sequential Gaussian simulation was used to populate the petrophysical properties. Representative models were selected for upscaling and flow simulation and subsequent well location selection.
Evaluation of the Potential for Reduction in Well Spacing of the Bakken Sand Pool, Court Field
Authors: Majcher M. B. , Estrada C. A. , Archer J. C.
Published: December 2007

In West Central Saskatchewan the Mississippian/Devonian middle Bakken Formation was deposited as NE-SW trending sand ridges, capable of producing heavy oil. In the Court field, the middle Bakken sand pool has been operated as a heavy oil waterflood for over 15 years with significant success. A review of an earlier field simulation was conducted, an updated model generated, and the potential for reduction in well spacing has been identified.

The lateral continuity of the sand ridge is variable due to post-depositional sinkholes. This structural complexity was mapped based on 3D seismic and well-logs and incorporated into the model. There were also stratigraphic disparities to take into account as discontinuous interbedded siltstones are potential flow barriers that create anisotropy in the permeability. Accordingly, grid orientation was modified to align axially with the main sand ridge permeability trends. Reservoir properties were re-assessed through correlation of cores, well-logs, porosity and permeability maps. Improved resolution was obtained with an increase in the amount of grid blocks used to account for the effect of grid orientation and numerical dispersion on the saturation distribution. A thorough analysis of pressure history, production/injection rates, waterflood performance by pattern interference, and dye injection tests were used to control the history matching process. The simulation model was then used to evaluate the downspacing potential and waterflood optimization of the middle Bakken reservoir.
Geostatistical Modeling Integral to Effective Design and Evaluation of SAGD Processes of an Athabasca Oil-Sands Reservoir: A Case Study
Authors: Robinson B. , Kenny J. , Hdez I. L. Hernandez , Bernal A. , Chelak R.
Published: December 2007

The design and implementation of a successful thermal recovery project starts with a representative static geological model. SAGD operating strategies of the steam chamber for optimum economical oil recovery with minimum SOR are largely controlled by the target reservoir geological and pressure environment.

This paper describes how geostatistical modeling techniques were used to build a static reservoir model over a 32-section area of a Fort McMurray oil sand reservoir. The model was constructed by using Roxar's Irap RMS modeling software. Irap RMS provided a platform that facilitated geostatistical mapping of horizons and populating the petrophysical properties over a 3.46 million cell static geological model. This paper describes how the petrophysical logs and core data from 33 wells in the study area were integrated into a coherent geostatistically based geological model from which any number of equiprobable realizations of the geological environment may be drawn.

The large scale geological model was built so that the impact of regional variability of reservoir quality on SAGD process strategies could be evaluated, optimized and readily assessed by using dynamic simulation techniques and by extracting and appropriately upscaling portions of the static reservoir model. This modeling strategy also allows risk analysis of geological uncertainty at a given location on SAGD performance to be evaluated by conducting and analyzing multiple dynamic simulation runs generated from equiprobable realizations of the static geological model. The use of geostatistical techniques to assess data quality and impact of geological uncertainty on the geological description are reviewed. The impact of this uncertainty on quantification of bitumen in place and its impact on establishing and prioritizing the placement of well pairs are also presented.

A review of the geology and the workflow followed by integrating petrophysics, core data, mapping of horizons, and rock types are discussed. The extraction and upscaling process used to create the dynamic simulation is described. The workflow strategy that was adopted allowed the definition and evaluation of SAGD operating strategies across the field to be evaluated concurrently and quickly with representative dynamic simulation models of a reasonable size.