This paper describes a trial project to evaluate autonomous inflow control device (AICD) technology to better manage water production in a large heavy oil field in Colombia. The Cajua block is part of the Rubiales field is in the Llanos basin of Eastern Colombia, and has reserves estimated at 7.5 billion barrels. One of the main production challenges is the high water cut, or BSW, driven by strong aquifer flow in the underlying sands of the Carbonera formation. Many wells experience early water break-through and must be produced above 95% BSW for long periods of time. Horizontal wells typically produce up to 8000 barrels per day of total fluid with electric submersible pump (ESP) on cold production, and do not utilize any thermal recovery methods. The loosely-consolidated sandstone reservoir has variable water saturation and permeability, which has continuously frustrated operators'’ attempts to manage water production ever since the Rubiales field was first brought online in the 1980's.
In late 2018, a three well pilot project was initiated to evaluate the ability of inflow control technology to manage water influx at the sandface of the horizontal completions. Three wells in the Cajua block were equipped with AICD screens and swellable packers to evaluate oil production and water cut. The AICD technology works by limiting water inflow based on fluid viscosity. Each segment, or compartment, of the horizontal wellbore is isolated by swellable packers, and the AICD creates a higher or lower drawdown on the reservoir depending on the fluid properties, favoring the inflow of high-viscosity heavy oil over the low-viscosity water.
The early production results show that AICD completions can effectively manage water production by delaying water break-through and restricting water inflow from the reservoir. Each of the three trial wells responded positively to the autonomous ICDs, allowing engineers to produce heavy oil wells more effectively with lower cumulative water volumes.
This project marks the first implementation in South America of AICD technology with rate-controlled production (RCP) valves to manage water production in a heavy oil field. It is also the second application worldwide, after Canada, to show that AICDs can effectively to manage water cut in a heavy oil, cold-production scenario.
Reservoirs in the Barents Sea are several times shallower than in other parts of the NCS, essentially due to recent uplift and erosion of younger sediments. A proper understanding of their geomechanics is considered paramount for their successful development. In turn, the lack of any available analogue makes the proper in situ measurement of key parameters compulsory.
The paper describes the planning and execution of an appraisal well solely dedicated to the purpose of geomechanics data acquisition in the shallowest oil reservoir on the NCS – i.e. coring, logging, XLOT and injection testing. It focuses on the operations conducted in the oil reservoir itself, which included an entirely novel multi-cycle injection test aimed at estimating the large-scale thermal stress coefficient of the formations around the well – i.e. the impact of the injection temperature on the fracture pressure of the formations.
Every operation in the well was challenging due to the sea depth being about twice that of the overburden thickness and to the formations being quite consolidated, which was met by careful iterative multidisciplinary-planning. The equipment was often taken to its limit and sometimes extended beyond its standard use – e.g. the metering systems.
The injection test itself could not be performed traditionally – i.e. use of surface data and downhole memory gauge. Instead, the downhole gauge data were sampled, pumped out and transferred to a remote site where real time advanced analytics was used to ensure that safety criteria were always met throughout the operation in terms of vertical fracture propagation and lack of reservoir compartmentalisation. In addition, this allowed adjusting the planned injection schedule to the exact formation's response, which could not be fully quantified ahead of time.
All the targets of the appraisal well were met. The injection test – i.e. the shallowest on the NCS and perhaps worldwide in an offshore environment – was performed successfully. Its main results are considered essential for a possible future field development – e.g. the injectivity is confirmed and, in addition, a significant thermal effect is proven.
The series of novel technologies deployed in the extreme environment presented in the paper can easily and beneficially be extended to more traditional reservoirs. This concerns performing multi-cycle injection tests on appraisal wells on a systematic basis to prepare and optimise the development plan, real-time monitoring through advanced analytics and adjustment of these tests, start-up of injection wells during field development, monitoring and optimisation of water injection schemes, etc.
Wells in the South Ratqa field often fill with sand. Ultra low bottom-hole pressure did not allow efficient sand cleanouts in several wells. Despite using massive amounts of nitrogen during clean out, and largest available CT size (2.375") to ensure enough annular velocity; severe fluid losses occurred into the formation, which resulted in decreased well production post clean outs, moreover handling energized returns has always been a logistic and safety hazard Recently, concentric coiled tubing (CCT) technology was employed for the first time in Kuwait and five wells were identified as viable fill cleanout candidates for which traditional cleanout methods had proved inefficient at best and many times unsuccessful. The system uses concentric coiled tubing and a special vacuum tool designed to apply a localized drawdown, which would deliver the sand particles through the Coiled Tubing / Coiled tubing annulus to surface. Returns were handled using H2S resistant lines into a desander. A carefully engineered cleanout program enabled removal of more than 12 MT of sand from four vertical wells, and also identified the formation damage in a horizontal wellbore. The identification of wellbore damage revealed the best intervention to cure the damage and eliminated speculative remedies that sometimes increased the damage done to reservoir. Additionally, the layout of well plots was designed in a very congested way to maximize output but made it impractical to have return pits, requiring mobile tanks to handle returns, while the energized nature of returns in conventional nitrogen jobs are dangerous to handle in a closed tank environment. CCT eliminated that hazard as the returns are not energized.
Warot, Gregory (Weatherford) | Wallace, Shawn (Weatherford) | Mostafa, Hassan (Weatherford) | Elabsy, Eslam (Weatherford) | Di Tommaso, Davide (Weatherford) | Abdelkarim, Aly (Weatherford) | Ciuperca, Constantin-Laurian (Weatherford)
Increased development of naturally and hydraulically fractured unconventional reservoirs from horizontal wells, drilled with oil-based muds, has created a need for high-resolution logging-while-drilling (LWD) borehole imaging tools capable of resolving fractures in this borehole environment. A new LWD ultrasonic borehole imager has been developed and tested to meet this need.
Borrowing from wireline ultrasonic imaging technology, a 250 kHz piezo-electric transducer was adapted to an LWD drill collar. The single transducer serves as both transmitter and receiver: transmitting an ultrasonic pulse, and measuring both the amplitude and two-way travel time of the acoustic reflection from the borehole wall. The LWD tool takes advantage of drill string rotation making a 360-degree scan of the borehole with a single fixed transducer. Finite element modeling and laboratory testing in artificial formations and a large limestone block were used to determine the spatial resolution of the image, as well as the sensitivity to downhole acquisition variables such as standoff, tool eccentricity, and mud attenuation. Prototype tools were then field tested in several horizontal wells to verify the functionality and image resolution under actual drilling conditions.
The borehole images from horizontal wells in unconventional and conventional reservoirs in the Middle East and the UK verified that tool responded as designed. These images, recorded in both oil-based and water based muds, revealed open and cemented natural fractures, drilling induced fractures and borehole breakout, fine-scale bedding, and other textural geological features such as vugs and stylolites. A variety of drilling-related borehole artifacts were also observed, including keyseats, stabilizer impressions in the borehole wall, tool marks from a rotary steerable tool, and gouges made by the bit rotating off bottom. The amplitude image proved more sensitive to fractures, bedding, and other geological features, while the travel time image, combined with input mud compressional velocity, provided a 360-degree borehole caliper image, showing the borehole size and shape.
Although high-resolution LWD electrical imagers have been available for years, these can only operate in conductive, water-based, muds. As most horizontal wells in both conventional and unconventional reservoirs are now drilled with oil-based muds, the development of a high-resolution ultrasonic imager capable of identifying natural and hydraulic fractures, fine-scale bedding, secondary porosity, and other small scale features in wells drilled with oil-based muds fills an important gap in LWD technology.
Chebyshev, Igor (Gazpromneft Science & Technology Centre) | Shapovalova, Alina (Gazpromneft Science & Technology Centre) | Zhigulskiy, Svetlana (Gazpromneft Science & Technology Centre) | Lukin, Sergey (Gazpromneft Science & Technology Centre)
The elaboration of weakly consolidated terrigenous collectors is accompanied by considerable removal of the solid particles. At one of the reservoirs of Western Siberia technique of evaluation and forecast of the volume of the removed solid particles on the basis of Finite-element modeling was tested.
Suggested way to evaluate the volume of the removed particles includes multiple stages. Reconstruction of the dynamic, static properties of the deformation and durability with taking into account the textural features of the rock samples. Construction of the 1D geomechanical models in target layer and exceeding coal-measures. Creation of three-dimensional model of mechanical qualities for realization of further calculations for the well which is included in contour of 3D-model. Finite-element modeling of the part of the trunk of the well in poroelastic arrangement for evaluation of plastic effects which are arising in collector - sandstone and non-collector – aleurolite, argillite with fruit her calculation of the volume of the removed solid particles.
It allows to determine the safest bottom hole pressure for the highest possible conservation of the stability of the well type "fishbone".
Digital technologies have a huge impact on our everyday life, including manufacturing industry, becoming a foundation for operations of large enterprises and corporations. Digital age offers unlimited opportunities while specifying rigorous requirements. Being essential for national economy oil and gas industry is not an exception: easy-to-reach oil is running low, hydrocarbon production is getting more accurate and science-based at all stages. It is necessary to search for different creative ways by using latest technologies to take the lead. Industry leaders create entire structures which provide analytical and scientific support of oil production and oil processing at all levels of manufacturing.
Halite precipitation from gas reservoir brines can cause significant decreases in hydrocarbon production or even complete blockage of the well. This has led to many gas wells either producing at diminished rates or being abandoned. Production decline related to halite scale is routinely treated with water washes either in a continuous system or with "mini squeezes" where water is batched in and held for few hours before production resumes usually with increased pressure. Introduction of halite inhibitors as part of the water wash or squeeze treatment has contributed to increased production by reducing the frequency and quantity of water used for treatment.
This paper summarizes the work performed to deliver to the industry a high-temperature, high-performance halite scale inhibitor. The product chemistry offers a true step-change in performance from existing technologies because of its high-temperature stability and halite inhibition efficiency at 420°F (bottom-hole temperature). An industry best-in-class rapid screening technique (kinetic turbidity test) was used to systematically evaluate all current technologies in the market place and to develop a detailed understanding on structure-performance relationships of functional groups. The resulting correlations led to synthesis of novel high-temperature stable chemistries with significantly superior inhibition on halite.
This paper also presents field cases of halite squeeze treatments from two different fields; an ultra hot (420°F) deep (17,460ft) dolomite gas well with severe halite deposition that required water washing every 48-72 hours and a shallow (6,000ft) hot (250°F) shale with erratic production where several water washes, work-overs and varied shut in periods did little to improve production. The ultra hot, deep well case history comes from a field in Texas where a detailed program of work was undertaken that led to squeezing in the halite inhibitor. Halite deposition had forced the operator to reduce production rates, with frequent workover to treat the well mainly with fresh water washes every 48 to 72 hours. After the introduction of the halite inhibitor, the gas well had been continuously producing for 40 days at the first instance and 60 days when the halite inhibitor dosage was increased. This is a marked improvement for the well and saves significant operating cost from well entries and deferred/lost production.
The paper describes a detailed methodology of halite inhibitor selection and the influence that temperature, pressure and salinity has upon application. Field application case histories share important lesson learned with regards to water washing volumes (small and large water washes) as well as the impact of extended shut in period on squeeze lifetime. These squeeze treatments provide valuable field insights to salt formation and prevention in gas wells and the use of the novel high-temperature inhibitor shows a new industry capability of inhibiting halite formation in hot gas well up to 450°F. This was proven by the successful field trials which showed an increase in the gas production at a higher draw-down rate without reducing the tubing/production pressure.
Lin, H. (CNOOC China Limited) | Xu, J. (CNOOC China Limited) | Liu, W. (China University of Petroleum) | Deng, J. G. (China University of Petroleum) | Xie, Tao. (CNOOC China Limited) | Jia, L. X. (CNOOC China Limited)
ABSTRACT: Frac&pack can serve the dual purposes of reservoir stimulation and sand control, which has been an important well completion technique in weakly consolidated sandstone reservoirs. At present, fracture initiation and propagation in weakly consolidated sandstone reservoirs hasn't been thoroughly investigated yet due to the low strength and high plasticity, resulti ng in lack of an effective evaluation method for fracturing parameters design. In this paper, a series of hydraulic fracturing physical simulation experiments were performed to investigate fracture propagation mechanism and the influences of fracturing parameters on the fracture morphology. In addition, a coupled hydro-mechanical numerical model based on rock mechanics and finite element method was employed to analyze the effects of formation permeability, fracturing fluid efficiency and injection rate on fracture initiation and propagation. The experimental and numerical results indicated that fracture fluid leakoff had significant influences on the fracture initiation and propagation in weakly consolidated sandstone. Single flat opening fracture tends to be generated under the condition of low permeability formation, high injection rate and high viscosity of fracturing fluid. Short and narrow fractures accompanied by shear dilation zones on both sides of the fracture would be generated if low efficiency fracturing fluid is used, which cannot accept proppants and thus are unable to prevent sand production. High efficiency fracturing fluid and high injection rate can induce longer and wider fractures as desired by the frac&pack operation. The results presented in this paper are expected to be beneficial for optimizing frac&pack designs in weakly consolidated sandstone reservoirs.
Frac&pack is an advanced sand control technology developed in recent years, which has become an important stimulation and sand control method for weakly consolidated sandstone reservoir. It can realize sand control and production enhancement simultaneously (Chen et al., 2012). Despite decades of field application, the initiation and propagation mechanisms of hydraulic fractures in weakly consolidated sandstone reservoirs are still not thoroughly understood because of the high porosity, high permeability and low strength characteristics of weakly consolidated sandstone (Guo et al., 2012). Laboratory studies and numerical simulations have been conducted on hydraulic fracturing of weakly consolidated sandstone, mainly focusing on the fracture initiation and propagation mechanisms of as well as factors that influence the fracture morphology. Li et al. (2007) investigated the effect of different perforating parameters, in situ stresses and injection rates on the fracture initiation pressure of horizontal wells. They found that the initiation pressure decreased with the increase of perforation depth and diameter. Liu et al. (2009) simulated the influences of well deviation, natural micro-fracture, and in-situ stress deviation on the fracture initiation and propagation using a true triaxial test apparatus and artificial samples. Khodaverdian et al. (2000) discovered that the morphology of hydraulic fractures in loose sandstone was considerably different from that of typical tensile fractures in competent rocks. Shear failure, plastic deformation and fluid-solid coupling at the fracture tip are crucial for fracture initiation and propagation. From their experimental results, de Pater et al. (2007) concluded that shear failure is the main cause of fracture initiation and propagation in weakly unconsolidated sandstone. Depending on the properties of injected fluid, fracture morphology of various complexities were observed, from single plane fractures to branching fractures. Germanovich et al. (2012) suggested that hydraulic fracturing of weakly consolidated sandstone involved multiple interacting complicated mechanisms (shear, tensile, shear dilatation and so on). In-situ stress was found a key factor influencing the peak injection pressure. In addition, it was found that high injection rate, low infiltration and high viscosity fracturing fluid were beneficial to fracture initiation.
Injection of blocking gels in the near wellbore of producer wells is a technique employed for water production control. A proven and effective alternative to control this water excess is the application of crosslinked gels. Water shut-off (WSO) treatments efficiency depends on several aspects such as reservoir fluid flow patterns, rock petrophysics, formation heterogeneities and gel characteristics. Although experimental laboratory tests previous field implementation, are many times underestimated, they provide valuable information that increases the chances of success. Integrating lab results with reservoir and field data creates a proper scenario that diminishes the uncertainties during field implementation. It is also crucial the support of a multidisciplinary team work while injecting the WSO tretament. This paper presents a successful water shut-off treatment specially designed for high temperature, applied in a production well located in Vizcacheras field, Mendoza Agentina.
As technology advances in horizontal well drilling, long horizontals completion are now preferred for producers aiming to explore more oil-bearing zones, especially in heavy or tight oil reservoirs. However, for strong waterdrive horizontal wells, abrupt increase of water-oil ratio and abounding unwanted water production severely affect the profitability of the field due to the constant decrease of oil production and premature well shutting.
The targeted reservoir of this work is a typical heavy oil reservoir with strong waterdrive. By December 2014, the average water cut for the two productive layers has increased 40-70%, for some wells especially, the water cut has exceeded 95% causing frequent well shutin. Therefore, to ensure the productivity of the horizontal wells, water shutoff has become a challenging and urgent task.
According to the aquifer identification and water influx diagnosis, 27 horizontal wells distributed in aforementioned two productive layers were first categorized into two groups in order of treatment difficulties, after which foam-assisted gel and gel treatments were designed and conducted.
For the three of the treated wells, the average water cut was significantly reduced from 80.3% to 48.0%. Although the gross liquid production rates were slightly reduced after treatment from 31.7 to 27.7 t/d, the oil production rate was considerably increased by 28.1 t/d. By January 2016, 4 500 t of the incremental oil was produced indicating the success of the water shutoff jobs. However, it should be noticed that the water cut of the N2 foam-assisted gel treated well started to rapidly rise after two months. This is probably caused by inappropriate foam/gel volume ratio. The water control strategies and field results in this heavy reservoir will provide the necessary clues for the design and application of water shutoff treatments for horizontal wells driven by strong water.