Skrettingland, K. (Statoil ASA) | Ulland, E. N. (Statoil ASA) | Ravndal, O. (Statoil ASA) | Tangen, M. (Statoil ASA) | Kristoffersen, J. B. (Statoil ASA) | Stenerud, V. R. (Statoil ASA) | Dalen, V. (Statoil ASA) | Standnes, D. C. (Statoil ASA) | Fevang, Ø. (Statoil ASA) | Mevik, K. M. (Knutsen Subsea Solutions) | McIntosh, N. (Knutsen Subsea Solutions) | Mebratu, A. (Halliburton) | Melien, I. (Halliburton) | Stavland, A. (Intl Research Inst of Stavanger)
Declining oil production and increasing water cut in mature fields highlight the need for improved conformance control. Here we report on a successful in-depth water diversion treatment using sodium silicate to increase oil recovery at the Snorre field, offshore Norway, utilizing a new operational concept of using a stimulation vessel as a platform for the large-scale injection into a subsea well. A custom modified 35,000 DWT shuttle tanker was employed for the field pilot. This paper describes the vessel preparations and the large-scale interwell silicate injection operation. The operational aspects of the large-scale interwell silicate injection include; identification of injection vessel requirements, major vessel modifications, chemical logistic, general logistics to site, major equipment set-up on vessel, subsea connection, mixing and pumping schedules, onsite QC, and real time monitoring. Experience from these operations and lessons learned are included in this paper.
After the injection of approximately 400,000 Sm3 (113,000 Sm3 preflush, followed by 240,000 Sm3 of sodium silicate gelant and 49,000 Sm3 of postflush fluid) at injection rates up to 4,000 Sm3/d, the injection from the vessel was stopped and the well was put on regular seawater injection. Following more than two years of regular production, transient pressure measurements, tracer testing and water cut data are presented from the ongoing comprehensive data acquisition program. These results demonstrate clearly the achieved in-depth flow diversion through a delayed breakthrough of injected tracers and lower water cut in the relevant production well.
Wang, D. (University of North Dakota) | Dawson, M. (Statoil Gulf Services LLC) | Butler, R. (University of North Dakota) | Li, H. (Statoil Gulf Services LLC) | Zhang, J. (University of North Dakota) | Olatunji, K. (University of North Dakota)
With the recent dramatic drop in oil price, production from ultra-tight resources, like the Bakken formation, may drop substantially. Since expenditures for drilling, completion, and fracking have already been made, existing wells will continue to flow, but oil rates will decline—rapidly in many cases. In a low oil-price environment, what can be done to sustain oil production from these tight formations?
We are testing a surfactant imbibition process to recovery oil from shales. We measured surfactant imbibition rates and oil recovery values in laboratory cores from the Bakken shale. After optimizing surfactant formulations at reservoir conditions, we observed oil recovery values up to 10–20% OOIP incremental over brine imbibition. However, whether or not surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil production rates in a field setting—which requires that we identify conditions that will maximize imbibition rate, as well as total oil recovery. In this paper, we describe laboratory evaluations of oil recovery using different core plugs. These recovery studies involved
(1) surfactant formulation optimization on concentration, salinity and pH, (2) characterization of phase behavior, (3) spontaneous imbibition, and (4) forced imbibition (flooding) with gravity drainage assistance.
In preserved cores, we observed: (1) Formulations using 0.1% surfactant concentration at 4% TDS salinity showed favorable oil recoveries (up to 40% OOIP). (2) Generally, surfactant formulations at optimal concentration and salinity were stable at high temperature (115°C). (3) Injectivity/permeability enhancements up to 75 percent occurred after acidification using acetic acid or HCl. (4) Wettability alteration is the dominant mechanism for surfactant imbibition. Of course, actions that increase fracture width will aid gravity drainage and oil recovery. This information is being used to design and implement a field application of the surfactant imbibition process in an ultra-tight resource.
Li, Yuxiang (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Churchwell, Lauren (The University of Texas at Austin) | Tagavifar, Mohsen (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Primary and secondary oil recovery from naturally fractured carbonate reservoirs with an oil-wet matrix is very low. Enhanced oil recovery from these reservoirs using surfactants to alter the wettability and reduce the interfacial tension have been extensively studied for many years, but there are still many questions about the process mechanisms, surfactant selection and testing, experimental design and most importantly how to scale up the lab results to the field. We have conducted a series of imbibition experiments using cores with different vertical and horizontal dimensions to better understand how to scale up the process. There was a particular need to perform experiments with larger horizontal dimensions since almost all previous experiments have been done in cores with a small diameter, typically 3.8 cm. We adapted and modified the experimental method used for traditional static imbibition experiments by flushing out fluids surrounding the cores periodically to better estimate the oil recovery, including the significant amount of oil produced as an emulsion. We used microemulsion phase behavior tests to develop high performance surfactant formulations for the oils used in this study. These surfactants gave ultra-low IFT at optimum salinity and good aqueous stability. Although we used ultra-low IFT formulations for most of the experiments, we also performed tests at higher IFT for comparison. Even for the higher IFT experiments, the capillary pressure is very small compared to gravity and viscous pressure gradients. We also developed a simple analytical model to predict the oil recovery as a function of vertical and horizontal fracture spacing, rock properties and fluid properties. The model and experimental data are in good agreement considering the many simplifications made to derive the model. The scaling implied by the model is significantly different than traditional scaling groups in the literature.
Dalmazzone, C. (IFP Energies Nouvelles) | Mouret, A. (IFP Energies Nouvelles) | Behot, J. (IFP Energies Nouvelles) | Norrant, F. (IFP Energies Nouvelles) | Gautier, S. (IFP Energies Nouvelles) | Argillier, J.-F. (IFP Energies Nouvelles) | Chabert, M. (SOLVAY)
A majority of the worldwide oil reserves is contained in carbonate reservoirs. Most of these reservoirs are naturally fractured and produce less than 10% of the oil in place during the primary recovery operations. It is noteworthy that this particularly low recovery ratio is essentially due to a low permeability associated to an intermediate or preferentially oil wettability. Consequently, the recovery of residual oil from these specific reservoirs is a great challenge. Changing the wettability from oil wet to preferentially water wet by using chemicals is one of the EOR technique that may be advantageously used to enhance the production rate. This chemical treatment consists in injecting an aqueous solution of surfactants or chemical additives to increase the water wettability and favour spontaneous imbibition into the porous matrix. We present a new test allowing a fast screening of aqueous solutions of chemicals that may be used to improve oil recovery from carbonate reservoirs. The test consists in depositing a drop of aqueous solution on a porous carbonate slice that has been treated to be preferentially oil wet before being put into dodecane. The evolution of the drop profile is then monitored as a function of time by means of a camera, which permits a simultaneous measurement of the interfacial tension between oil and water, contact angle between the water drop and the porous matrix and spontaneous imbibition. Various types of non-ionic and anionic surfactants belonging to different families have been tested and ranked to identify the best candidates among these chemicals. Finally, a Nuclear Magnetic Resonance technique was used to follow spontaneous imbibitions of selected candidates in miniplugs representative of the carbonate slices used in the screening test. NMR's results confirmed the classification issued from the fast screening test.
Favorable microemulsion rheology is required for achieving low surfactant retention and economic viability of chemical EOR. Co-solvents play a pivotal role in obtaining favorable microemulsion rheology as well as many other aspects of chemical EOR. We measured the partitioning of co-solvents between phases to better understand their behavior and how to select the best co-solvent for chemical EOR. There is an optimal co-solvent partition coefficient for microemulsion systems. Commercial co-solvents used for chemical EOR are actually mixtures of different components. We used HPLC to measure the partitioning of the constitutive components of phenol ethoxylate co-solvents between oil and water phases and between microemulsion and excess oil and water phases. These measurements show that the components partition independently and the partitioning of individual components is often different from the average. The co-solvent partition coefficients between oil and water were systematically evaluated as functions of the number of ethylene oxide groups, number of propylene oxide groups, temperature, salinity, and the equivalent alkane carbon number (EACN) of the oil. Novel alkoxylate co-solvents were also evaluated for chemical EOR. The novel alkoxylate co-solvents can be more effectively tailored to match the characteristics of different crude oils. Coreflood experiments were conducted to investigate co-solvent transport and retention. Co-solvents were identified that showed excellent performance and low retention.
Mishra, Ashok (Conoco Phillips) | Abbas, Sayeed (Conoco Phillips) | Braden, John (Conoco Phillips) | Hazen, Mike (Conoco Phillips) | Li, Gaoming (Conoco Phillips) | Peirce, John (Conoco Phillips) | Smith, David D. (Conoco Phillips) | Lantz, Michael (TIORCO, a Nalco Champion Company)
This paper is a field case review of the process and methodologies used to identify, characterize, design, and execute a solution for a waterflood conformance problem in the Kuparuk River Unit in late 2013. In addition, post treatment analysis in a complex WAG flood will be discussed. The Kuparuk River Field is a highly fractured and faulted, multi-layer sandstone reservoir located on the North Slope of Alaska. Large scale water injection in the field was initiated in 1981 and overall the field responded favorably to waterflood operations. In 1996, Kuparuk implemented a miscible WAG flood in many areas of the field. However, natural fault and fracture connectivity has resulted in some significant conformance issues between high angle wells in the periphery. Methodologies employed to identify and characterize one specific conformance issue will be outlined. Details of diagnostic efforts, and how they were used to identify, characterize and mitigate an injector/producer interaction through a void space conduit will be discussed. The solution selected to resolve this conformance issue involved pumping a large crosslinked hydrolyzed polyacrylamide (HPAM) gel system. The solution used a tapered concentration design with one of the highest molecular weight HPAM polymers available. Before execution of this solution, extensive history matching and modeling of the solution design and benefits were used to justify this effort. These modeling efforts and their projections will be reviewed. This solution was pumped into the offending injector in late 2013, and offset producers were carefully monitored for gel breakthrough. The polymer treatment design parameters, including rates and pressure limits were used to generate an effective solution. A discussion of this active design approach, a complete review of the well problem dynamics, treatment operations, products used, and potential complications associated with these products will be discussed. Post solution execution performance analysis was difficult due to the active nature of this MWAG flood. A variety of plotting and analysis techniques were used to identify and quantify the results. A discussion of these results will be provided. Finally, a summary of lessons learned, and a limited discussion of future plans will be presented.
Ghasemi, M. (Petrostreamz AS) | Astutik, W. (Petrostreamz AS) | Alavian, S. A. (PERA AS) | Whitson, C. H. (PERA AS/NTNU) | Sigalas, L. (Geological Survey of Denmark and Greenland) | Olsen, D. (Geological Survey of Denmark and Greenland) | Suicmez, V. S. (Maersk Oil & Gas A/S)
This paper presents a novel technique to determine multi-component diffusion coefficients for CO2 injection in a North Sea Chalk Field (NSCF) at reservoir conditions. Constant volume diffusion (CVD) method is used, consisting of an oil-saturated chalk core in contact with an overlying free-space, which is filled with the CO2. The experimental data are matched with an EOS-based compositional model.
Transport by diffusion controls the dynamics of the constant-volume system, together with phase equilibria, allowing a consistent estimation of diffusion coefficients needed to describe the observed changes in system pressure.
We conduct two experiments at reservoir condition: one utilizes a core plug saturated with live-oil, and the other with stock tank oil (STO). Once the experiments are completed, EOS-based compositional simulation is performed to match the experimental data using the oil and gas diffusion coefficients as history matching parameters. The modeling work is conducted with a commercial reservoir simulator using a two dimensional radial grid model to describe the experimental setup.
The experiment utilizes a vertically-oriented core holder with a height of 92 mm and 37.6 mm in diameter. An outcrop chalk core with a sealing sleeve is mounted in the core holder, which has the same diameter and a height of 64.6 mm, thus resulting in an overlying void space. The system is initially saturated with oil at reservoir condition. CO2 is then injected from the top, forming an overlying CO2 chamber, and displacing oil towards the bottom of the core holder. Once CO2 fills the overlying bulk space, the system is isolated with no further injection or production.
The CO2 and oil reach and remain in equilibrium locally at the gas-oil interface throughout the test, initiating and maintaining the diffusion mechanism. Diffusion of CO2 into the oil results in a decreasing pressure, which is the main history matching parameter.
The multi-component diffusion coefficients are found to match the model pressure-time prediction to the experimental data. This suggests the modelling workflow incorporates a representative EOS model and the main transport dynamics controlled by diffusion are being treated properly.
The two main challenges in the modeling are (1) the limitation on setting an appropriately-high permeability for the CO2 chamber, and (2) the reservoir simulator neglects compositional dependency of diffusion coefficients.
Proper simulation of CO2 injection in fractured chalk reservoirs requires the ability to model multi-component diffusion accurately. The proposed CVD-method provides such modeling capabilities. Our modeling and experimental work indicate the novelty of the CVD method to determine the diffusion coefficients of a system where diffusion is the dominant displacement mechanism. The fact that the oil is contained within a low-permeability chalk sample reduces density-driven convection that could result due to non-monotonic oil density changes as CO2 dissolves into the oil.
Partitioning interwell tracer tests (PITTs) have been used to estimate remaining oil saturations during waterflooding. Compared to core tests, well logs and single well tracer tests, PITTs sample a much larger representative elemental volume (REV) and provide interwell estimates of remaining oil saturation. The test has historically been used to estimate residual oil saturation (Sorw) after waterflooding between injector-producer pairs when the oil is essentially immobile. During polymer flooding, especially with viscous oil, additional oil is displaced and traditional means of interpreting PITTs are not valid. In this paper we present the information gained from conducting a polymer PITT and the saturation estimated during the PITT. This paper presents mechanistic insights into tracer and polymer velocities during the PITT and hence allows for an estimate of remaining oil saturation left behind after polymer flooding and also presents a new log-normal fit which can be used to match multiple flow path responses as is seen in actual field tracer data and reduce the error in estimates of remaining oil saturation. The polymer PITT therefore allows characterization of polymer flood efficiency and is a useful tool in polymer flood evaluations in heterogeneous reservoirs.