The Samarang Field is a complex stacked reservoir system, consisting of multiple sand packages separated by thin but continuous shale layers. The general reservoir structure is a faulted anticline. Most reservoirs have an oil rim with associated gas cap and have some natural water influx.
During the redevelopment study for Samarang field, an extensive IOR/EOR study was performed, focusing on the largest reservoirs of the field. A full-field simulation model for the M reservoirs (over 25% of the field STOOIP) was built and calibrated with the historical production, pressure, and fluid-contact movement data. Using this model and various cross section models, an extensive investigation was conducted to evaluate the benefit of injecting water and hydrocarbon gas to improve oil recovery in these reservoirs. The results indicated that updip water injection into the gas-cap region of the reservoirs is beneficial in improving oil recovery. Simultaneous updip water and downdip gas injection gave the highest oil recovery, compared to other injection schemes. This Gravity Assisted Simultaneous Water and Gas injection scheme (GASWAG) improved the sweep efficiency of the lower section on the inner part of oil rim with the downward movement of water and at the same time, increases the swept efficiency of the upper section on the outer part of oil rim with upward movement of injected gas.
The investigated EOR schemes for M reservoirs could potentially increase the cumulative oil production by 20 MMSTB compared to infill drilling only. This increase represents ~7% of OIIP. A significant fraction of this oil production can be produced by reactivating existing idle wells during the application of the EOR process. This paper describes the investigation of the gas and water injection to improve oil recovery in the M reservoir layers.
This paper proffers some guidelines for using a surfactant-polymer (SP) flooding operation so that the feasibility and profit can be optimized. Many successful projects have shown that surfactant-polymer flooding is an effective means to improve oil recovery after or during water-flooding. Here, the guidelines for evaluating whether a surfactant-polymer flood is suitable for a given field are developed and the procedure for a full implementation is summarized. These guidelines cover primary screening, laboratory measurements, reservoir simulation, economic analysis, pilot testing, and field application. Detailed methods also are presented for the optimization of chemicals (including compatibility tests between chemicals and reservoir fluids and rock), well pattern and spacing preparation, and slug and injection process design. The correlations between the above phases of operation are also emphasized. The work offers reservoir engineers a reference for decision-making in SP flooding.
Oil-production from Enhanced Oil Recovery projects continues to supply an increasing percentage of the world's oil. Taber, et al., (1997) estimated that 3% of the worldwide oil production came from EOR. That number has continued to increase and in the future it is expected that EOR will eventually produce the majority of the world's oil. Thus choosing the most efficient recovery method becomes increasingly important to petroleum engineers. Using a surfactant-polymer solution as an injectant is a technique to enhance oil recovery from a water-flooded reservoir by improving both displacement and sweep efficiencies. Polymer functions work by adding certain concentrations of water-soluble polymers to injection water to increase the injectant viscosity; surfactant functions work by adding certain concentrations of surfactants to injection water to reduce the interfacial tension (IFT) between the displacing and displaced phases. The polymer makes the displacing phase more closely match the viscosity of the in situ oil and thus achieves a more favorable mobility ratio (Hornof, et al. 1983; Needham and Doe 1987; Maitin, 1992; Melo, et al., 2005). Surfactant-polymer flooding reduces the interfacial tension between the trapped crude oil and its associated brine. Flow of the surfactant formulation through the reservoir allows the oil droplets trapped in small pore spaces to deform and become mobile oil. When the interfacial tension is reduced the capillary forces are reduced and the oil is allowed to flow. Once they are released these oil droplets then coalesce and form a new flowing oil bank. The more viscous polymer solution is used behind the surfactant to keep the surfactant and oil bank moving toward the producing wells. Surfactant-polymer processes result in a final oil saturation much lower than that produced by water-flooding and the more efficient reservoir sweep reduces the amount of injection fluid needed to recover a given amount of oil (Beghelli, et al., 1989; Roshanfekr, et al., 2008). A number of reviews on the application and benefits of surfactant-polymer flooding exist. Over the past thirty years, quite a few of surfactant-polymer flooding projects have been conducted on modest scales in China, especially at China's largest field, Daqing (Liu, et al. 2004).
Artun, Emre (Chevron ETC) | Ertekin, Turgay (Penn State University) | Watson, Robert William (Pennsylvania State University) | Al-Wadhahi, Majid Ahmed (Sultan Qaboos University) | Miller, Bernie J. (Miller Energy Technologies LLC)
Gas cyclic pressure pulsing is an effective EOR method in naturally fractured reservoirs. A limited number of studies concerning this method in the literature focuses on specific reservoirs and the optimum operating conditions have not been broadly investigated. In this study, we present a detailed parametric study of the process from both operational and reservoir perspectives. Incremental oil production, peak oil rate and net present value (NPV) are considered as the important markers for the performance criteria. The necessary analyses are performed for a single-well, dual-porosity, compositional reservoir model. In the first part of the study, parametric studies are conducted to develop a better understanding of the operational parameters affecting the process performance, in the shallow, naturally fractured, and depleted reservoirs of Big Andy Field in Eastern Kentucky. These include analyses of various design parameters such as soaking period, cycle rate limit, number of cycles, cycle and cumulative injected gas volumes. In the second part of the study, reservoir characteristics are investigated. Comparative discussions are presented between cases with CO2 and N2 as the injected gas on reservoir fluids of different compositions (heavy, black and
volatile oils). Influences of area, thickness, fracture/matrix permeabilities, initial reservoir pressure and temperature on the process are studied. It is observed that N2, as a lower-cost gas, would be a better choice than CO2 in the Big Andy Field. With the oil price used in this study, the cost of injected gas becomes relatively insignificant in economic considerations. Increased income due to increased oil production overcomes the increased costs with higher volumes of gas. The way reservoir characteristics affect the process performance is very similar in cases with CO2 and N2, but differs significantly in different reservoir fluids. Thicknesses ranging between 20 and 50 ft produced more favorable results. A higher efficiency was observed with smaller drainage areas (5-8 acres) in the presence of
heavy oil. For the cases with volatile and black oil, it is seen that the process efficiency is not significantly altered by the area. The phase behavior of the reservoir fluid is very important for the performance of the process. Initial pressure/temperature of the reservoir, and therefore, the initial fractions of gas/liquid phases affect the process efficiency in a more pronounced manner.
Strauss, Jonathan Patrick (Petroleum Development Oman) | Alexander, David Mobey (Petroleum Development Oman) | Al Azri, Nasser Said (Petroleum Development Oman) | Al-Habsi, Mohammed (Petroleum Development Oman) | Al-Musallami, Talal (Petroleum Development Oman) | Koning, Maartje (Petroleum Development Oman) | Eriavbe, Francis Eseoghene (Shell Petroleum Dev Nigeria SPDC) | Mukmin, Mukmin (Petroleum Development Oman) | Al-Jarwani, Riyadh Mohammed (Petroleum Development Oman) | Landman, Anke Jannie (Shell Intl. E&P Co.)
This paper covers EOR development concept screening from a sub-surface perspective. The field in question is a medium sized heavy oil field with complex geology that is located in South Oman. The two front running concepts considered are steam and polymer flood, both of which present their own challenges. Common to both concepts are the difficulty in obtaining adequate conformance in a field that is characterised by high and highly variable permeabilities in a channelised environment and that includes lateral extensive shales that break the system up into vertically distinct sand units. Additional challenges are presented by a permeable regional scale aquifer, an erosive top surface that reduces the equivalent oil column (EOC) in the core of the field leaving thicker columns laterally close to the edge aquifer and the friable nature of the sand that makes sand control necessary. Challenges specific to steam are the relatively high initial pressure, inferred connection to a regional-scale strong aquifer, and relatively high CAPEX associated with the development. Polymer on the other hand represents a relatively untested option for oil with viscosities of greater than 400cP as are present in this field.
Modelling work used to identify risks and the subsequent development potential of these two options is presented. Potential development and maturation solutions for the various options are discussed and concepts are compared.
The structure is a four-way dip closed anticline caused by outward salt withdrawal and dissolution from salt walls outside the field limits (Figure 1). No extensional forces are required to develop this structure. A significant feature of the structure is its ‘bow-tie' shape, which is caused by the embayment in the south-east. This embayment is a result of the salt dissolution and is flanked by faults. The oil bearing reservoir is characterised by thin 10-20m Middle to Lower Gharif Permian age fluvial sandstones, of which the two upper Middle Gharif units (HSGHM4a and HSGHM4c) are the main pay that the developments target and will continue to focus upon (Figure 2). The lowest unit, HSGHLG2, is only oil bearing across the crest of the field and contains a small oil column with bottom water. It only accounts for a very small proportion of the total STOIIP and if it were to be brought on production is subject to extreme water coning behaviour and as such does not represent an attractive target for development. The three oil bearing units are separated by laterally extensive floodplain shales (HSGHLG1 and HSGHM4b) and unconformably overlain by the Nahr Umr Lower Cretaceous shales (Figure 2). The Gharif formation is underlain by the extensive glacial lacustrine ‘Rahab Shale'. Additional non-extensive shales are also present within the units, particularly in the uppermost HSGHM4c unit. The unconformity has resulted in some of the upper units of the reservoir being absent; no Upper Middle or Upper Gharif sands are present in the crest. In the three cores obtained in the field, the sandstones are observed to be very friable. Core permeabilities are typically high with 60% of the population above 1D and an upper limit of 10D that is more a reflection of measurement capability and core integrity than intrinsic permeability. Production performance supports the presence of multi-darcy (>5D) sands and three wireline mini-DSTs give single sand unit horizontal permeability averages of 4 to 8D.
ASP (alkali, surfactant, polymer) flooding has obtained good results in the field. However, it has serious "scale?? and "emulsion?? and "chromatographic separation?? problems, and because of the reaction of alkali with the formation, it cannot be used at high temperature conditions. A relatively pure surfactant that attains ultra-low Interfacial Tension (IFT) between crude oil and formation water without adding alkali into the system needs to be developed.
A mechanism (or condition) for surfactants to form ultra-low IFT at low concentrations is put forward. According to this mechanism, the chemical structure of 5 series of surfactants is designed, more than 30 specific surfactants were synthesized, all the above surfactants types and most of the specific surfactants attained ultra-low IFT (less than 9X10-3mN/m) with the crude oil and formation water systems. In the above surfactants, a series of "Betaine Amphoteric Surfactants?? (a relatively pure surfactant with only one or two effective molecular structures) are the most promising. The surfactant was comprehensively evaluated. Besides the make-up water, it does not require additional "alkali??, "salts??, "co-surfactants??, "alcohols?? or "solvents?? into the system; the IFT between the driving fluid and crude oil of many reservoirs can reach an ultra-low IFT value at concentrations of only 10 ~ 3000ppm; it is tolerant to salinities up to 229,000ppm, divalent ions 21,000ppm, temperatures 98?. Test on cores shows that the recoveries of flooding by SP (surfactant, polymer) systems using this surfactant are higher than that by ASP systems using alkyl-benzene-sulphonates as the surfactant and NaOH as the alkali, its total recovery can reach above 70% OOIP. Micro-visual oil displacement experiments show that this surfactant can also change the pore surface wettability and further increase the recovery.
The above results show that this is a very promising surfactant for chemical flooding, it can be used in very challenging reservoir conditions (very few reservoirs have conditions harsher than those listed above); the mechanism to achieve ultra-low IFT , which is put forward, is useful to the development of new surfactants for EOR and to chemical EOR itself; Surfactants that do not require alkali, co-surfactants, alcohols, salts and solvents in the system to attain ultra-low IFT should promote better understanding of the function of surfactants in chemical flooding.
Daqing Oilfield is one of the earliest which develop displacement technology by polyacrylamide (PAM). 1 ton polymer can increase 100 to 120 tons of oil, the recovery from above 40% to nowadays 50%. In view of the geological and physicochemical characteristics, a series of technologies have been developed, such as polymer flooding mechanism, the productivity forecasting, proposal optimization, domestic excellent quality polymer production, surface injection, downhole separate layer injection, and separate layer testing during injection, etc.. The oilfield is characterized by heterogeneous multi-layer sandstone reservoir, during polymer flooding, separate layer injection technology is also needed to alleviate the interlayer differences, enhance oil recovery and improve the whole development effect.
After polymer flooding in main oil layers, the object of polymer flooding in Daqing Oilfield turned to laminated layers with lower permeability and more interlayer differences, these layers were compatible to polymer solution with medium or low molecular weight, using polymer solution with the same molecular weight for displacement will cause difficult injection into these poor layers, and thus have an impact on polymer flooding effect. In order to solve this problem, a new technology is developed through injection of polymer solution with different pressure and different molecular weight in different layers, which can realize the adjustments of both separate layer polymer molecular weight and injection rate, and also field test was carried out in the polymer injection blocks, good results of well stimulation have been seen.
This paper briefly introduces the development and practice of separate layer polymer injection technologies, presents its focus on the principle, string structure and parameters of eccentric different molecular weights polymer injection technology and its field applications in Daqing oilfield.
Full-field production forecasting is a key requirement for facilities design and economic analysis during development of a
Field Development Plan (FDP). However, forecasting using relatively fine-grid thermal simulation models with over one
million grid blocks can require days or weeks to complete a run. Within the timeframe of a typical FDP project, teams must
often evaluate multiple geologic and reservoir engineering scenarios, development concepts, and uncertainty ranges in highsensitivity
variables in terms of their impact on production streams, costs, and overall project economics. During this
evaluation process, fast and flexible forecasting methods are favored over slower but perhaps more accurate methods.
Mukhaizna field is a giant heavy oil field in South Sultanate of Oman and is presently under steamflood. Following a period
of cold production development involving the drilling of 75 horizontal producers and resulting in very low recovery, a
steamflood FDP was developed over a period of six months. Based on this FDP, drilling of hundreds of horizontal producers
and thousands of vertical injectors is planned for the next 20 years. Mukhaizna is the first large-scale commercial steamflood
to use horizontal producers and vertical injectors.
Full field production forecasting for Mukhaizna was performed using a novel, fit-for-purpose workflow. Pattern-scale, finegrid
geologic models representing areas of distinctive flow unit and permeability architecture were built and simulated to
develop pattern production type curves. Full-field production forecasts were obtained by scaling up production streams from
type-curve simulation using a scale-up tool prototyped in Excel. Inputs to the scale-up tool included pattern STOOIP, drilling
sequence/schedule, production targets, and facilities constraints. Once type curve simulation was completed, any field
development scenario could be forecasted within a few hours. This paper 1) describes how the type-curve models were
defined, generated, and simulated; 2) how the detailed scale-up methodology was developed and applied in the Mukhaizna
Mukhaizna field is a heavy-oil discovery located in South Sultanate of Oman. The field, comprising a main North Structure
and a smaller South structure, was discovered over 30 years ago and has a long history of field appraisal and development
study activities. The field contains viscous, low gravity (14o to 18o API) crude oil in the shallow Permian-age sands of the
Primary "cold?? production from Upper and Middle Gharif reservoirs in the crestal area of the North structure has been ongoing
since 2000 as a precursor to future thermal development. 75 horizontal producers were drilled before 2004. A thermal trial in
the North structure consisting of six cyclic steam stimulation (CSS) wells on a pattern spacing of 465 ft was constructed in
2004 and 2005, but not put on production until 2006.
Hussein, Assef Mohamad (Schlumberger) | Minton, James (Schlumberger Reservoir Geomechanics CoE) | Rawnsley, Keith David (Petroleum Development Oman) | Li, Qiuguo (Schlumberger DCS) | Zhang, Xing (Schlumberger) | Koutsabeloulis, Nick C. (Schlumberger)
Steam injection into a shallow fractured and faulted reservoir has the potential to change the stress profile of the subsurface in such a way as to induce microseismic events that could eventually reactivate faults and fractures, especially if steam injection temperature is significantly high and fracture spacing is small. A 3D mechanical earth model (MEM) of a thermal gas/oil gravity recovery process illustrates the potential for steam to facilitate drainage by reducing viscosity of the heated matrix oil, leading to compaction that might be offset by upward movement of the surface in response to high steam temperatures. In our extreme case, the upward movement at ground level could be as high as ~26 cm over 35 years. High levels of vertical deformation are increasingly likely where faults extend to the surface. Understanding these processes is important to ensuring the safety of the facilities over extended production times in environments of this kind.
Stoll, Martin (Shell E&P International Ltd) | Al-Shureqi, Hamad (Shell E&P International Ltd) | Finol, Jose (Shell E&P International Ltd) | Al-Harthy, Said Amor (Petroleum Development Oman) | Oyemade, Stella Nneamaka (Shell Petroleum Dev Nigeria SPDC) | de Kruijf, Alexander (Petroleum Development Oman) | Van Wunnik, John N.M. (Petroleum Development Oman) | Arkesteijn, Fred (Shell EPT-R) | Bouwmeester, Ron (Shell Intl. E&P BV) | Faber, Marinus J. (Shell Intl. E&P BV)
After two decades of relative calm, chemical EOR technologies are currently revitalized globally. Techniques such as alkaline surfactant-polymer flooding, originally developed by Shell, have the potential to recover significant fractions of remaining oil at a CO2 footprint that is low compared to, for example, thermal enhanced oil recovery, and they do not depend on a valuable miscible agent such as hydrocarbon gas. On the other hand, chemical EOR technologies typically require large quantities of chemical products such as surfactants and polymers, which must be transported to, and handled safely in, the field.
Despite rising industry interest in chemical EOR, until today only polymer flooding has been applied on a significant scale whereas applications of surfactant-polymer (SP) or alkaline surfactant-polymer (ASP) flooding were limited to multi-well pilots or to small field scale. Next to the oil price fluctuations of the past two decades, technical reasons that discouraged the application of chemical EOR are excessive formation of carbonate or silica scale and of strong emulsions in the production facilities.
Having identified significant target oil volumes for ASP flooding, Petroleum Development Oman (PDO), supported by Shell Technology Oman, carried out a sequence of single-well pilots in three fields, sandstone and carbonate, to assess the flooding potential of tailor-made chemical formulations under real subsurface conditions, and to quantify the benefits of full-field ASP developments.
The paper discusses the extensive design process that was followed. Starting from a description of the optimisation of chemical phase behaviour in test tubes as well as core-flood experiments, we elaborate how the key chemical and flow properties of an ASP flood are captured to calibrate a comprehensive reservoir simulation model. Using this model we evaluate PDO's single-well pilots and demonstrate how these results are used to design a pattern-flood pilot.
Lanier, Gary Howell (Petroleum Development Oman) | Kok, Apollo Leonard (Shell Italia E&P SpA) | Young-Mclaren, Andrea (Petroleum Development Oman) | Al-Riyami, Murshid Mohammed (Petroleum Development Oman) | Ambusaidi, Muneer Ahmed (Petroleum Development Oman) | Van Wunnik, John N.M. (Petroleum Development Oman)
In the South of Oman, several billion barrel heavy oil fields are located in a clastic reservoir setting. Many of the fields typically contain 200 - 2000 cP viscosity oil in good quality reservoirs at depths of about 1000 meters from the surface. These fields have usually been densely developed, often with horizontal wells, and produced cold for many years. Nevertheless, most of the oil-in-place will not be produced conventionally unless a suitable EOR technique is applied. Steam and polymer flooding are two potential EOR techniques, but each option faces technical and economic challenges. This paper focuses, for one of the fields in the Haima group, on the common challenge of well count reduction and utilizing the existing horizontal well stock by a combination of creative thinking and novel technology.
New vertical well patterns lead to high well counts and vertical injectors generally exhibit poor conformance in relation to existing horizontals. Even when the existing wells are closed in, the horizontal sections, in particular from dual-laterals, can often not be abandoned and will keep acting as conduits in a vertical pattern layout. New horizontal wells with conformance control equipment can provide a cost effective solution that compliments the existing horizontal well stock and provides better conformance and injectivity than vertical wells. Conformance control equipment that can withstand steam temperatures has recently been developed. For both the steam and polymer flooding options, the production technology and reservoir engineering aspects of horizontal well conformance control will be discussed in detail and compared to vertical wells. Simulation modelling results will demonstrate that even in relatively homogeneous reservoirs, conformance issues can significantly reduce recovery if not properly mitigated. In particular, injector versus producer conformance control, the number of discrete completion intervals and novel technology solutions will be discussed.