Alusta, Gamal Abdalla (Heriot-Watt University) | Mackay, Eric James (Heriot-Watt University) | Collins, Ian Ralph (BP Exploration) | Fennema, Julian (Heriot-Watt University) | Armih, Khari (Heriot-Watt University)
This study has focused on the development of a method to test the economic viability of Enhanced Oil Recovery (EOR) versus infill well drilling where the challenge is to compare polymer flooding scenarios with infill well drilling scenarios, not just based on incremental recovery, but on Net Present Value as well.
In a previous publication (Alusta et al., 2011, SPE143300) the method was developed to address polymer flooding, but it can be modified to suit any other EOR methods. The method has been applied to a synthetic scenario with constant economic parameters, which has demonstrated the impact that oil price can have on the decision making process.
The method was then applied and tested (Alusta et al., 2012, SPE150454) with varied operational and economic parameters to investigate the impact in delaying the start of polymer flooding to identify whether it is better to start polymer flooding earlier or later in the life of the project. Consideration was also given to the optimum polymer concentration, and the impact that factors such as oil price and polymer cost have on this decision. Due to the large number of combined reservoir engineering and economic scenarios, Monte Carlo Simulation and advanced analysis of large data sets and the resulting probability distributions had to be developed.
In this paper the methodology is applied to an offshore field where the choice has already been made to drill infill wells, but where we test the robustness of the method against a conventional decision making process for which there is historical data. We do this by performing calculations that compare the infill well scenario chosen with a range of polymer flooding scenarios that could have been selected instead, to identify whether or not the choice to drill infill wells was indeed the optimum choice from an economic perspective.
We conclude from all the reservoir simulations and subsequent economic calculations that the decision to drill infill wells was indeed the optimum choice from an economic perspective.
Hassenkam, Tue (U. of Copenhagen) | Mathiesen, Jesper (U. of Copenhagen) | Pedersen, Christian (U. of Copenhagen) | Dalby, Kim (U. of Copenhagen) | Stipp, Susan (U. of Copenhagen) | Collins, Ian Ralph (BP Exploration)
Field tests have demonstrated that oil production from sandstone reservoirs increases when injected water salinity is low, i.e. ~1500 ppm total dissolved solids (TDS). In core plug tests performed at reservoir conditions, low salinity flooding has been responsible for incremental recoveries ranging from about 5 to 38%. Previous work has suggested that for the low salinity effect to manifest itself, the oil must contain polar components, the formation water must contain divalent cations and clay must be present in the reservoir, but a clear understanding of the mechanism, from fundamental chemical and physical principals, is still subject to debate.
In the work reported here, an atomic force microscope (AFM) has been used in force spectroscopy mode to investigate the nature and magnitude of the interaction between hydrocarbon molecules with carboxylic acid end groups and the pore surfaces of oil reservoir sandstones. By functionalizing the AFM tip with polar molecules we have been able to measure, quantitatively, the adhesion forces between these molecules and the mineral surfaces under 36,500 and 1500 ppm TDS artificial seawater (ASW) solutions.
Collecting these measurements in two-dimensional arrays, known as force maps, revealed that adhesion was highest on the quartz grain surfaces during exposure to the high salinity solutions and it decreased when salinity decreased in nearly all cases. The drop in adhesion was observed through several high to low salinity cycles. We interpreted certain small features that were visible on the quartz surfaces to be clay that had grown directly on the sand grains from solution during diagenesis. Adhesion on these clay surfaces also changed with modifications in salinity. We observed no difference in behaviour whether the sandstone was preserved or cleaned; both types of core demonstrated a clear low salinity response.
For over 10 years research has been carried out on the impact of low salinity waterflooding on oil recovery. Data derived from corefloods, single well tests, and log-inject-log tests have shown that injecting low salinity water into an oil reservoir should result in a substantial increase in oil recovery in many cases. The results varied from 2 to 40% increases in waterflood efficiency depending upon the reservoir and composition of the brine.
In 2005, a hydraulic unit was converted to inject low salinity brine into an Alaskan reservoir, by switching a single injection pad to low salinity water from high salinity produced water. An injector well and 2 close production wells were selected within a reasonably well constrained area. A surveillance programme was devised which included capturing produced water samples at regular intervals for ion analysis and the capturing of production data.
Detailed analysis of the production data, and the chemical composition of the produced water, demonstrated an increase in oil production and provided direct field evidence of the effectiveness of LoSal™ at inter-well scales. Additionally, the response of the reservoir to low salinity water injection was confirmed by single well chemical tracer test.
In parallel, laboratory studies have led to mechanistic understanding of LoSal™ in terms of multiple-component ionic exchange (MIE) between adsorbed crude oil components, cations in the insitu brine and clay mineral surfaces. The results clearly show that the enhanced oil production and associated water chemistry response was consistent with the MIE mechanism proposed.
The oil production data have been modeled using an in-house developed modification to Landmark's VIPTM reservoir simulation package. An excellent match for the timing of the oil response was obtained which provides a good basis for predicting the result for large scale application of LoSal™ flooding.
Reservoir formations are often very heterogeneous and fluid flow is strongly determined by their permeability structure. Thus, when a scale inhibitor (SI) slug is injected into the formation in a squeeze treatment, fluid placement is an important issue. To design successful squeeze treatments, we wish to control where the fluid package is placed in the near-well reservoir formation. In recent work1, we went "back to basics?? on the issue of viscous SI slug placement. That is, we re-derived the analytical expressions that describe placement in linear and radial layered systems for unit mobility and viscous fluids. Although these equations are quite well known, we applied them in a novel manner to describe scale inhibitor placement. We also demonstrated the implications of these equations on how we should analyse placement both in the laboratory and by numerical modelling before we apply a scale inhibitor squeeze. An analysis of viscosified SI applications for linear and radial systems was presented both with and without crossflow between the reservoir layers.
In this previous work, we assumed that the fluid being used to viscosify the SI slug was Newtonian. However, the question has been raised concerning what the effect would be if a non-Newtonian fluid was used instead. We mainly consider the effect of shear thinning although our analysis is generally applicable if the non-Newtonian flow rate/effective viscosity function is known. We address the questions: (i) Does the shear thinning behaviour result in more placement into the higher or lower permeability layer (in addition to the effect of simple viscosification)? (ii) Can the shear thinning effect be used to design improved squeeze treatment?
Background and Introduction
Chemical scale inhibitors (SI) have long been applied in downhole "squeeze?? treatments to prevent mineral scale formation[2-8]. In a homogeneous reservoir layer, adsorption may be the only retention mechanism governing the SI return from the well. However, reservoir formations are rarely homogeneous but are made up of highly heterogeneous rocks which may have a layered or more complex structure as determined by various sedimentological, structural and diagenetic factors. Here we will consider only layered systems where the various layers have different permeabilities, k (and porosities, F) in the near-well formation. In such systems, SI placement within the formation is an additional aspect of a squeeze treatment that must be considered since this may affect the SI returns.
Scale inhibitors are typically applied as aqueous solutions at concentrations, typically in the range 10,000 - 150,000 ppm. These solutions usually have a viscosity (µ) close to that of an injection brine; i.e. ~1 cP at 20°C and 0.3 cP at 100°C. Therefore, apart from a slight temperature effect, the injected brine displaces formation water (FW) at unit mobility. Also, for lighter oils, a unit mobility displacement is often involved although viscosity and relative permeability effects may be more important in heavier oils. In unit mobility injection into a heterogeneous layered linear or radial system, as shown schematically in Fig. 1, the fluid placement into layer i is governed solely by the (kh)i product. That is, injecting fluid at a total volumetric flow rate of QT into an N-layer system of the type shown in Fig. 1, then flow into layer i, Q i , is given by:
It can easily be shown that this is true for unit mobility displacement in a linear or a radial system with or without crossflow. However, this well established result might foster the belief that linear and radial systems are also very similar under viscous slug injection with and without crossflow and this is not the case.
The formation of sulfate scales arising from the injection of seawater into hydrocarbon-bearing formations for pressure maintenance and secondary oil recovery has been a significant problem in many onshore/offshore operations. To address this, batch scale inhibitor squeeze treatments, scale removal, and modification of the injection brine (sulfate removal, produced water injection, aquifer water injection) have been applied with varying degrees of success. The development of deepwater projects, where conventional scale control technology may be uneconomic for the control of mineral scale, has required a re-evaluation of the methods of scale inhibitor deployment.
For the past five years, BP Exploration has been developing a novel approach to the application of scale inhibitors with the objective of eliminating the requirement for both active scale inhibitor squeezing and scale removal operations. This has been achieved by the development of nano-sized, controlled release, solid scale inhibitor particles that can be added to the injection water such that the particles pass through the formation and release the scale inhibitor into the fluids near the production wells.
The principle of solid particle transport in porous media is demonstrated using core flooding tests and reservoir modelling. This confirms that solid particle transport is possible and that minimum retardation relative to the injected brine can be achieved. Static and dynamic release characteristics of the scale inhibitor formulations evaluated to date will be presented. The factors to be considered in the commercial manufacture and initial field trial results will also be presented together with the economic justification for this type of scale control process.
This technology offers a revolutionary scale control process that could eliminate the need for sulfate-reduction plants whilst still providing effective scale control within the reservoir and near-wellbore region for deep water developments.
The injection of seawater into oil-bearing reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales to the injection and production wells during such operations has been much studied. The current deep water subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way. To this end, the challenge of scale control during the lifecycle of water injection, production and onto produced water reinjection has been reviewed for a number of fields by the authors.
This outlines the risk assessment process that should be undertaken to select the most economical and effective scale control methodology (which for sulfate-based scale could be seawater injection with scale inhibitor squeeze treatments to maintain production, or sulfate reduction of the injection water - with or without the need to scale inhibitor squeeze). In the case of sulfate reduction, parameters to be investigated include the degree of desulfation required to minimise the scale risk of downhole scale formation, the impact that the degree of fluid mixing will have on the resulting brine (from injection to production) and the impact that the desulfated brine will have on scale control during produced water reinjection.
The paper draws upon a wide range of technical inputs to make scale management decisions including: computer modelling techniques (e.g., deposition models that incorporate the kinetics of sulfate scale formation at low supersaturation ratios); reservoir simulation of fluid mixing and reaction; the resulting produced brine chemistry; laboratory generated coreflood data to assess chemical selection for scale inhibitor squeeze and produced water application; and field results that will demonstrate the impact of the type of injection water source on the long term manageability of such deepwater projects. Finally, the paper outlines in detail the particular issues associated with the full economic assessment of low-sulfate water injection versus full sulfate seawater injection.
The scale-control challenges for two North Sea carbonate reservoirs are reviewed in this paper. While carbonate reservoirs are not the largest source of hydrocarbons within the North Sea, they are very significant on a global basis.
The mechanism of scale-inhibitor chemical retention observed for phosphonate, polymer, and vinyl sulfonate copolymer (VS-Co) inhibitors on carbonate-reservoir substrates is outlined. Chemical placement represents the most significant technical challenge when performing scale-inhibitor squeeze treatments into fractured chalk reservoirs. Examples from more than 50 field treatments applied in reservoirs E and V, in which both phosphonate and VS-Co chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated clear potential for significant extension in treatment lifetime by changing from a phosphonate to a VS-Co-based scale inhibitor. The selection and qualification of chemical-placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined. To this end, novel technologies to enhance conventional scale-inhibitor-chemical placement are vital to economic success during waterflood projects.
Conventionally, scale mitigation is achieved using chemical inhibitors either by squeeze treatment into the reservoir or continuous injection. However, with new fields encountering increasingly more challenging environments, or when the economic impact of chemical intervention by squeeze treatment is large (e.g. subsea fields with poor bullhead chemical placement), other methods of scale control such as the use of low sulphate sea water (LSSW), must be considered during the front end engineering and design (FEED) stage of a field development. Nevertheless, for conventional sulphate reduction packages (SRP's) that reduce the sulphate concentration in the injected sea water typically towards 40 - 50 ppm, there remains a residual scaling risk and the requirement for periodic squeeze treatments.
Previous work reported at the 2004 SPE Oilfield Scale symposium (SPE 87465) examined the level of sulphate reduction required to mitigate the requirement for even periodic squeeze treatments against barium sulphate scale.This showed that sulphate levels of 20 ppm were required in order to prevent scale formation under down hole production conditions, although it was also demonstrated that thermodynamically the system remained oversaturated with barium sulphate.
This paper expands considerably on this preliminary "field specific" case and examines the impact of LSSW on the scaling kinetics across a broad range of formation water compositions (barium ranging from 150 ppm to 650 ppm) and at temperatures between 80ºC and 120ºC. The paper therefore investigates the relationship between scaling kinetics and thermodynamics in relatively mild scaling environments and illustrates that whereas extremely low levels of sulphate would be required to completely prevent scale from a thermodynamic viewpoint, the kinetics of scale formation may prevent scale precipitation under down hole production conditions, with additional continuous injection inhibitor applied at wellheads to protect flow lines etc.In summary, this paper presents results from an extensive series of long term dynamic flow and pseudo static performance tests designed to determine the relative impact of thermodynamics and kinetics on the residual barium sulphate scaling risks associated with the injection of LSSW for pressure support.
Mineral scale formation and deposition on downhole and surface equipment is a major source of cost and reduced production to the oil industry.This paper describes a novel semi-quantitative kinetic approach to predicting the location of barium sulfate formation and deposition.The key conclusions of this work are:
There is probably negligible formation damage arising from barium sulfate deposition in the near well bore region.
There are three kinds of barium sulfate precipitation in the well depending upon the scaling tendency (saturation ratio) in the produced brine (it is assumed that the higher saturation ratio values for barite at the bottom of the well is a consequence of mixing of high sulfate brine from sea water breakthrough with high barium brine formation water). The location of the scale formation can be predicted from knowledge of the nucleation induction time coupled with mass transfer arguments. The equations describing these have been developed in this paper and applied to some general illustrative cases demonstrating the applicability of the approach. In particular, a method has been developed for predicting the location of scale formation and deposition at low saturation ratios such as developed when sulfate-removal is utilized as a barite scale control technology.
Scale control is conventionally achieved by the use of chemical inhibitors, introduced to the production system either by squeeze treatment into the reservoir or continual injection into the well.However, as new field developments encounter more challenging production environments or when the associated economic impact of chemical intervention is large (e.g. subsea completed wells with poor chemical placement by bullhead treatments, or limited access to wet subsea wellheads), other methods of scale control such as sulfate removal must be considered during the front end engineering design (FEED) stage for the development. However, the final selection of a fields scale management strategy relies on various technical and economic factors which themselves are controlled not just by the severity of the anticipated scaling regimes but also on the proposed field development plan.For subsea completed wells, especially those located in deepwater, the initial field development concept and drainage strategy can have a significant bearing on the costs ultimately associated with various scale management strategies and can, in extreme cases, significantly reduce the Net Present Value (NPV) of the project.The decisions taken at the concept selection stage for scale management in such environments are therefore crucial to the success not only of the chosen scale management strategy but also to the fields economic viability.
This paper reviews the various challenges associated with scale formation and control in subsea and deepwater environments and the impact that different field design scenarios may have on the potential success of various scale management options. In particular, the paper will focus on technical, economic and risk-based analysis conducted for a number of new and proposed subsea field developments with different scaling challenges.The options for scale management in selected subsea and deepwater developments including examples from the North Sea (Shallow water), offshore Angola, and Gulf of Mexico cases will be reviewed.The impact of the various risks and uncertainties associated with determining the severity of the scale challenge (including the quality and source of initial water compositions, the accuracy of simulation tools used for the prediction of future scaling challenges prior to field production, the ability to effectively squeeze treat and place scale inhibitors into particular wells and the potential for changes in the field drainage strategy) are assessed in terms of the total costs associated with particular cases.In summary, the paper will describe the decision process used at the pre-FEED stage to determine a field scale management strategy for different development concepts.Detailed economic analysis of different options considered in recent field cases will be presented to support the different strategies adopted.