Sahin, Secaeddin (Turkish Petroleum Corporation) | Kalfa, Ulker (Turkish Petroleum Corporation) | Uysal, Serkan (Turkish Petroleum Corporation - Library) | Kilic, Harun (Turkish Petroleum Corporation) | Lahna, Hakki (Turkish Petroleum Corporation - Library)
With initial oil in place of 1.85 billion barrels, Turkey’s largest oil field Bati Raman was discovered and put on stream in 1961. The field attained a primary recovery of lower than 2% due to the poor quality of the rock and fluid properties of the reservoir and a low energy drive mechanism.Immiscible carbondioxide (CO2) flooding project of Bati Raman commenced in 1986, and it has been successfully implemented for over the period of quarter century to drive up oil rate of the field. Oil production, which was only 1.500 STBD prior to the EOR project, hasreached to 14.000 STBD level by increasing 8-9 times at the peak performance period, showing a declining trend thereafter. The project is still active; the
on-going application in the field has been a unique and successful process. It added significant value to the field and in the long run it turned out to be anexcellent application showing a 3-4 times increment in the recovery factor. Nevertheless, the amount of CO2 required for one extra barrel of oil has tendency to increase and, it is a fact that the CO2 injection will soon complete its mission remaining a great deal of oil in the reservoir. Therefore, there is a great incentive to implement another effective enhanced recovery process in the field to drain this remaining oil. Now the field is under consideration for another marginal and unique application. No analogous worldwide is yet known: Steam Injection Pilot in already CO2 flooded Deep-Heavy Oil Fractured Carbonate reservoir. There are a few similar applications, but their depths are incomparably shallower than the Bati Raman field. A steam injection pilot with two injectors, one observer, and eleven producers at the crest was
commenced in September 2012. The purpose is to heat and pressure up the reservoir from the top and produce oil from the neighboring producers. This paper documents design, implementation and early operating results of this pilot project being conducted in the Bati Raman field.
The advantages of using the low salinity water injection (LSWI) technique to improve oil recovery in carbonates are well pronounced; however, the mechanism behind it is still ambiguous. This paper uses geochemical modeling to investigate the main mechanism of low salinity water injection (LSWI) in carbonate oil reservoirs. The geochemical modeling was performed using two geochemical simulators (UTCHEM and PHREEQC).
New geochemical flow and transport simulations show that anhydrite dissolution may contribute to wettability alteration by LSWI, but is not the main contributor. These simulations also show that the change in pH and the resulting change in surface charge expand the electrical double layer (EDL) which in turn alters the wettability and improves oil recovery. The emphasis in the literature is on the effect of pH causing in-situ generation of surfactants, whereas in this study the effect of pH on the surface charge is emphasized.
This study shows that the results of LSWI in carbonate rocks can be best explained as wettability alteration due to the change in surface charge as opposed to anhydrite dissolution. The improvement in oil recovery by LSWI in carbonates also depends on temperature, pressure, mineralogy, oil type, initial rock wettability state, and injected water composition, so the results in other carbonates might vary.
Magnus tertiary miscible gas injection started in 2002 through a WAG scheme yielding 18 mmstb of incremental oil to date at a very high net efficiency of 3.5 mscf/stb. Pore scale efficiency is very good with 8% Sorm based on core flood data. Areal and vertical gas sweep efficiency is sub-optimal based on 4D seismic and PLT data. This paper focuses on studies carried out to explore possibilities to improve sweep efficiency and the resulting pattern optimization programme in the field.
Magnus Sandstone Member (MSM) consists of a number of stacked turbidite sand lobes separated by intra-formational shales. The WAG scheme has been managed by considering MSM as a single reservoir unit. As the patterns have matured, it has become apparent that the scheme could be optimized by further vertical separation of the reservoir units. Key surveillance data such as 4D seismic monitoring gas movement, PLTs, well performance and open hole saturation logs have been coupled with simulation to explore options for sweep improvement. These options involve changing sweep direction by means of adding new perforations and shutting off zones, complete reversal of the patterns – i.e. converting producers to injectors and vice versa, and use of chemicals for flood diversion.
Evaluation of multiple options resulted in a phased WAG optimization programme of which the first phase is being proposed for execution in 2014. A behind flood front core is planned in 2015, which is expected to help calibrate the optimization programme by quantifying Sorm and the degree of vertical sweep achieved in the field. Relatively low cost options were identified to improve the sweep as opposed to drilling new wells. Integration with the operations team was the key in creating a business case for pattern optimization on a 30-yrs old, bed space constrained platform.
The workflow of this study and the learnings are applicable to mature patterns in any WAG scheme. Optimizing the WAG patterns enables more efficient use of the available gas, which -given that cost of gas is a significant component of any gas injection project- makes this more commercially viable and cost effective tertiary recovery option.
Puerto, Maura C. (Rice University) | Hirasaki, George J. (Rice University) | Miller, Clarence A. (Rice University) | Reznik, Carmen (Shell Global Solutions) | Dubey, Sheila (Shell Global Solutions) | Barnes, Julian R. (Shell Global Solutions) | vanKuijk, Sjoerd (Shell Global Solutions)
The effect of hardness, Ca++ and Mg++, was investigated on equilibrium phase behavior of alcohol-free systems made with blends of Alcohol Propoxy Sulfates and an Internal Olefin Sulfonate. Aqueous surfactant solutions and systems with water-to-oil ratio ~1 were studied. Experiments were performed at ~25°C and 50°C, the latter below the thermal stability limit of APSs. Hard brines tested were synthetic Sea Water, and 2*SW and 3*SW, brines having double and triple all ion concentrations in SW. Also tested were NaCl-only brines of the same ionic strength as the hard brines. The oil was n-octane, which has frequently produced optimal surfactant systems close to those for crude oils of interest.
This work applies to surfactant and is useful for surfactant-polymer floods.
Optimal blends of four APS surfactants with IOS15-18 formed microemulsions of high oil solubilization suitable for EOR applications at 25°C and 50°C. However, oil-free aqueous solutions of optimal APS/IOS15-18 blends exhibited cloudiness and/or precipitation, making them unsuitable for injection at 25°C and 50°C in 2*SW, 3*SW, and corresponding NaCl solutions. This behavior results from substantial content in optimal blends of IOS15-18, which has poor tolerance to high salinities and hardness. In SW the aqueous solution of the optimal blend of Branched alcohol67 PO7 sulfate and IOS15-18 was clear. A salinity map was prepared for this blend, which should be useful in selecting compositions for injection for processes where injection and reservoir salinities differ.
More options for alcohol-free processes in SW were obtained by blending Branched alcohol67 PO7 sulfate with other APSs and Alcohol Ethoxy Sulfates. Several such blends formed microemulsions with high octane solubilization and clear aqueous solutions in SW at 25°C near optimal conditions. An APS/AES blend was found to form suitable microemulsions in SW with a crude oil at its reservoir temperature near 50°C.
The results illustrate advantages of using alkoxylated sulfates at low and intermediate temperatures and salinities. Blends of alkoxylated sulfates merit further study for EOR processes with hard brines because they may facilitate obtaining clear aqueous solutions for injection.
Millimeter-sized superabsorbent polymer (SAP) or called preformed particle gel (PPG) are gaining attention and popularity for use in conformance-improvement treatments. The strength of PPGs is important to their performance as a conformance control agent. Measuring conventional gel strength has been always accomplished by applying load to single isolated samples with certain geometry. However, determining the strength of sugar-like PPG particles with irregular shapes is a challenging task. Previous publications showed the use of different methods to evaluate swollen PPG strength. However, those methods are either costly or inaccurate. We designed an apparatus that can be used to fast and accurately evaluate PPG strength.
We present PPG strength evaluation results using a simplified experimental apparatus. It composed of a positive displacement hand pump and a specially-designed piston accumulator. The top cap of the accumulator has a hole connected to the pump by tubing and fittings. The bottom cap is a stainless steel screen plate with multiple holes. The size of the holes represents the pore throat size. During the experiments, we put swelling PPG on top of the screen plate and below the piston, gradually increasing the pressure to push the piston until particles pass through the holes. The maximum pressure that pushes particles out of holes will be the threshold pressure of a particle moving through a pore throat. This pressure is representing the strength of the gel and can be used in PPG characterization.
We observed that PPG are prone to stiffen with brine concentration increase which caused an increase in threshold pressure. We also witnessed that PPG injection pressure depends chiefly on the swelling ratio and the screen hole size. However, the injection pressure does not increase significantly with injection rates. Behavior consistent with the real-time injection pressure and injection rate change observed during PPG treatments in oilfields. We also found that the gel threshold pressure have an excellent correlation with its elastics module which is measured by rheometer.
This method can provide a simple fast practical technique to quantitatively evaluate particle gel strength in laboratory and on site during PPG treatment process.
Shale gas reservoirs have been proposed as feasible choices of location for injection of CO2 and/or N2 because this method could enhance recovery of natural gas resources, while at the same time sequester CO2 underground. In this paper, a fully coupled multi-component multi-continuum compositional simulator which incorporates several transport/storage mechanisms is developed. To accurately capture physics behind the transport process in shale nanopores, Kundsen diffusion and gas slippage are included in the flow model. An extended Langmuir isotherm is used to describe the adsorption/desorption behavior of different gas components and the displacement process of methane as free gas. Pressure-dependent permeability (due to rock deformation) of natural fractures induced by hydraulic fracturing is also considered in the simulator.
In addition, modeling of complex fracture networks is very crucial for simulating production of shale gas reservoirs because there exists various scales of fractures with multiple orientations after the fracturing treatment for horizontal well. In this work, a hierarchical approach which integrates EDFM with dual-continuum concept is adopted. The hybrid model includes three domains: matrix, major hydraulic fractures and large-scale natural fractures (described by EDFM), and micro-fractures in SRV region which are modeled by dual-continuum approach. Embedded Discrete Fractures Model (EDFM) is an efficient approach for explicitly simulating large-scale fractures in Cartesian grid instead of complicated unstructured grid. Moreover, a nested-grid refinement method is used to capture the fluids transfer from matrix to fractures.
Fully implicit scheme is applied for discretizing fluid equations, and the corresponding Jacobian matrix is evaluated by Automatic Differentiation with Expression Templates Library (ADETL). The AD-Library framework allows wide flexibility in the choice of variable sets and provides generic representations of discretized expressions for gridblocks. Several simulations and sensitivity analysis are performed with the developed research code for determining the key factors affecting shale gas recovery. Modeling studies indicate that the properties of fracture networks could greatly influence methane production. Different injection strategies including huff-n-puff process are also evaluated for optimizing production of multi-fractured horizontal well. Results show that CO2/N2 injection can be an effective approach with great application potential for enhancing shale gas recovery.
When both Fe(II) and oxygen are present in aqueous HPAM solutions, redox couples can substantially degrade polymers. In the absence of dissolved oxygen and oxidizing agents, HPAM can be quite stable in the presence of Fe(II). HPAM can also be reasonably stable in the presence of dissolved oxygen in the absence of Fe(II) and free-radical generating impurities, if certain conditions [oxidation-reduction potential (ORP), pH, brine composition, temperature] are met. In field applications of chemical flooding, a gray area exists where significant iron (either solid or dissolved) may be present, along with low levels of dissolved oxygen (e.g., <50 parts per billion, ppb). Large differences of opinion exist on how to treat this situation, including (1) removing all iron, (2) removing all dissolved oxygen, (3) addition of free-radical scavengers or adjustment of ORP and/or pH, and (4) no action.
This paper describes an experimental study of stability of an HPAM polymer and an HPAM-AMPS terpolymer with varying initial levels of dissolved oxygen (0, 10, 20, 50, 200, 500, 2000, and 8000 ppb), Fe(II) (0, 1, 5, 10, 20, 30, 50, 100, and 500 parts per million, ppm), and Fe(III) (0, 1, 5, 10, 50, 100, and 500 ppm). A special method was developed to attain and confirm dissolved oxygen levels. Stability studies were performed at 23°C and 90°C.
With ≤2000 ppb initial O2, the dissolved oxygen dropped to 0 ppb within one week. Our findings reveal that once the available dissolved oxygen is depleted, no further oxidative degradation of polymer occurs. The results were insensitive to Fe(II) concentration for initial O2 ≤2000 ppb. For initial O2 of 8000 ppb, polymer degradation increased significantly with increased Fe(II). Solution viscosity losses were insignificant for O2 concentrations of 500 ppb or less.
In the studies with Fe(III), the iron crosslinked the polymer to form a visible gel. However, in the studies with Fe(II), we saw no evidence of gel formation, suggesting when Fe(II) reacted with O2, any Fe(III) that formed was converted to solid iron oxide before any polymer crosslinking could occur. The significance of these observations for field applications will be discussed.
Mukherjee, J. (The Dow Chemical Company) | Norris, S.O. (Anadarko Petroleum Corporation) | Nguyen, Q.P. (University of Texas at Austin) | Scherlin, J.M. (Anadarko Petroleum Corporation) | Vanderwal, P.G. (The Dow Chemical Company) | Abbas, S. (The Dow Chemical Company)
In this paper we describe the design of a CO2 foam pilot in the Salt Creek field in Natrona County, WY. CO2 foam technology was chosen as a promising candidate to improve sweep efficiency in certain target patterns. The Second Wall Creek (WC2) sandstone formation is the primary producing interval, with a net thickness of about 80 feet and at a depth of approximately 2,200 feet. The first screening step towards identifying a pilot area involved a detailed study of the geologic features, injection-production characteristics, and operational aspects of numerous patterns in the field. An injector centered five-spot pattern was selected for the pilot. A surfactant formulation was developed that provided the desired foam response at reservoir conditions, and also met preliminary economic and operational expectations. The foam characteristics of the surfactant were further investigated by performing core-flood experiments. A history matched reservoir simulation model was developed to forecast the performance of the field in the absence of foam and thus provide a baseline to compare with the anticipated foam response. The model was later calibrated with foam performance data and used to guide the implementation of the pilot and to forecast field performance. The pilot was initiated in September 2013. Initial results will be discussed.
A hierarchical history matching algorithm is proposed that sequentially calibrates reservoir parameters from the global-to-local scale in consideration of parameter uncertainty and the resolution of the data. Parameter updates are constrained to the prior geologic heterogeneity and are performed parsimoniously, or only to spatial scales at which they can be resolved by the history data. In the first step of the workflow, a genetic algorithm (GA) is used to calibrate and assess the uncertainty in global parameters (e.g., regional fracture properties, aquifer strength) that influence reservoir energy and field-scale flow behavior. To identify the reservoir volume over which each parameter region is applied, a novel heterogeneity segmentation is developed from spectral clustering theory. After an ensemble of calibrated model realizations is identified using the GA, the ensemble is reduced via a cluster analysis to define a variance-preserving subset of the members for the second step of local or high-resolution parameter calibration. Each member of the subset is calibrated to well-level phase rate and pressure data using a sensitivity-based scheme. To improve the ill-posedness of each high-resolution inverse problem, the heterogeneity field is parameterized in the spectral domain using the Grid Connectivity-based Transform (GCT) to provide a compressed representation that captures only the sensitive geologic trends. The CGT concurrently imposes geological continuity during calibration and promotes minimal changes to each prior ensemble member.
The proposed calibration workflow is applied to a structurally complex, fractured reservoir located offshore Peru. The reservoir is modeled as dual porosity and single permeability (DPSP). In the global calibration step, the field water production rates, gas rates and average reservoir pressure are matched using the GA together with zonal multipliers that represent spatial variation in aquifer strength, fracture porosity and a matrix-fracture coupling parameter. In the subsequent local step, the well-by-well production histories are matched through calibration of the most uncertain grid-cell parameter, fracture permeability, which is characterized using the GCT parameterization. The final calibrated models are consistent with geologic interpretation and are currently being applied for field development strategies.
The Bakken reservoirs represent a large untapped resource of oil. One of the challenges is extracting these crude oils from their low-permeability formations at economic rates. These reservoirs contain multiple pay zones, including some with carbonate (dolomite) lithology. Recent common practice is to drill horizontal wells and perform a series of large, multi-stage hydraulic fracture treatments. The fractures penetrate deeply into the reservoir and promote more efficient drainage of the oil.
This situation suggests that a surfactant technology designed to enhance oil recovery from fractured carbonate formations is a fit for these typical Bakken cases with Middle Layer complex fractured lithology. The concept of this technology is to incorporate appropriate surfactant formulations at a low dosage in the well stimulation fluids. If properly designed, such additives in the fracture fluids will penetrate into the highly oil-saturated matrix or natural fracture region and accelerate the extraction of the oil in place by rapid imbibition. This extracted oil can readily move from the matrix into the propped fracture system for production. Another benefit of the additive is its engineered property to leave the matrix or nature fracture face water-wet, facilitating oil movement during production.
This paper presents a study of a series of such stimulation fluid additives developed for enhanced oil recovery. Over 10 of special customized product blends were evaluated in laboratory for their effectiveness in increasing recovery of Bakken crude oil samples. Tests included compatibility with formation brine, surface tension and interfacial tension, wettability alteration, emulsion tendency, recovery factors from spontaneous imbibition with crude oil and formation brine, and compatibility with proposed fracturing fluids. These results show that more than one of these products improve recovery of Bakken crude oil by spontaneous imbibition from both outcrop limestone cores and from Bakken core material. The best of these products is recommended for field application.