Azim, Shaikh Abdul (Kuwait Oil Company) | Chowdhuri, Sankar (Kuwait Oil Company) | Sahib, Mohammad Raffi Madar (Kuwait Oil Company) | Mohammad, Tarek Abdel Gawwad (Kuwait Oil Company) | Abdulkarim, Anar (Halliburton) | Samie, Mohamed (Halliburton) | Aki, Ahmet (Halliburton)
Real-time azimuthal acoustic measurements were introduced recently in the logging-while-drilling (LWD) industry. For the first time, this technology was used as part of the bottomhole assembly (BHA) to acquire information related to principal stress orientations in the deltaic to marine Zubair clastic sequence of onshore Kuwait.
A deviated 8.5-in. hole section of the well was planned through sand-shale sublayers with a borehole inclination ranging from 46 to 88°. This section is characterized by time sensitive borehole deterioration and significant variations in pore pressure. These factors result in severe hole instability and ultimately stuck pipe events and require relatively high mud weights to maintain wellbore stability. LWD azimuthal acoustic technology, free from chemical sources, was used for the first time both in drilling and wipe modes to facilitate time-lapse field stress and wellbore stability analysis.
Principal stress orientations were identified from three different sources, including borehole breakouts from azimuthal acoustic caliper, density image, and acoustic anisotropy evaluation. The results were then compared with the existing offset well data and an existing geomechanical 3D model. Variations in observed stress orientation, seismic reflection pattern, and pressure history in offset wells were used to map a fault that is responsible for bypassed oil and for the occurrence of tar and gas. The interpretation was extended to other low throw strike-slip faults; additional fault compartments were identified that could affect the pressure maintenance scheme of the field.
This paper discusses the planning, design, and use of LWD azimuthal acoustic technology in this case history well. It also describes the viability, integrity, and reliability of the interpreted results and their use in a detailed geological interpretation in terms of stress orientation, fault trapping, and areal fluid variation. The optimization of real-time drilling operations and petrophysical data acquisition requirements are also investigated to improve future field development and overall reservoir management strategies.
Gas condensates and volatile oil reservoirs are simulated using compositional simulation or modified black-oil (MBO) approaches to account for composition changes in the reservoir
Regarding the EOS tuning parameters, for example, some investigators prefer to regress on the binary interaction parameters (BIP) and the (O's) parameters of the EOS. Others have chosen the volume shift, BIP's, and critical parameters as matching parameters. Also, there is a newer approach where some investigators have chosen to vary the plus fraction molecular weight followed by the volume shift parameters.
In this study, we have constructed an EOS model program to perform the five commonly used tuning approaches. We have investigated the different tuning approaches using a large data base of PVT samples spanning the range of black-oils through volatile oils and gas condensates (including rich gas condensates and lean wet gases). We have compared the different tuning approaches based on two criteria: (1) the quality of match after applying the tuning procedure, as indicated by the absolute average error (AAE), and (2) the percentage deviation in the tuning parameters from their original values.
The tuning of many reservoir fluids using the different approaches has shown that some approaches were more superior to others and usually yielded excellent matches. While the other tuning approaches gave moderate to good matches. Based on this work, we were also able to give practical recommendations on tuning approaches that yield consistent EOS models.
Tight gas reservoir development has long been affected by 1) complex flow profiles and 2) the impact of very low permeability on reservoir productivity. Where well tests (WT) buildup is very short, interpretation becomes difficult and results often are ambiguous. Most WT of tight, dry gas wells are of short duration; thus, such tests typically lead to multiple interpretations and open-ended conclusions. Adding to the complexity, simulation software packages often fail to adequately model flow in fracture networks.
A series of well tests were conducted in tight sandstone, dry gas, naturally fractured reservoirs post-induced hydraulic fracturing. The tests were conducted for long durations: 100 hours in most cases, and 1,000 hours in two extended well-test cases. The WT responses from these tests were ambiguous.
We have investigated possible direct causes of the ambiguous results, including wellbore, geology, and specific well conditions. However, because the WT response has been found repeatedly in a variety of regions around the world, it may not be related to any of these.
After investigating in multiple manners, including the use of simulation software, we argue that the anomalies in the WT response may reflect a step in the scale-dependent properties of the fracture network.
Using mixtures of metal oxides nano-particles suspended in water to form an injectable nano-fluid (rather than single nano-fluid) has been investigated. The use of mixtures nano-fluids proved its ability as an EOR agent and its advantages over single nano-fluids. This paper investigates the different parameters that affect the oil recovery when using nano-fluids mixtures to suggest an optimum scenario for applying this technique.
Four sandstone cores were used in the experiments. The first core was used to test effect of the dispersing fluid salinity on the oil recovery. A core was flooded three successive times, each time till oil production stopped completely, with the same mixture of nano-particles but dispersed in different brine concentration. It was concluded that dispersing fluid salinity has negligible effect on ultimate oil recovery.
The usage of nano-fluid injection after water flooding was tested on the second core. The core was water flooded with one pore volume followed by nano-fluid injection. The results of the experiments show the possible successful formation of an oil bank and sustaining oil production when nano-fluid mixture is used after waterflooding.
The third core was used to check the possibility of using a nano-fluid slug instead of continuous injection due to its economical advantage. The experiments proved the viability from recovery point of view and the advantages from an economic point of view of using slugs of nano-fluid mixtures rather than continuous injection of nano-fluids.
Finally, combining between low salinity technique and nano-fluid injection was tested in the fourth core. The experimental results show that combining low salinity and nano-fluid mixtures injection (in different slugs) can add additional reserves.
Proppants are required in hydraulic fracturing operations in the oil and gas industry. They consist of solid particles with specific strengths and are used to keep the rock fractures open in order to increase well production. They can be naturally occurring sand grains or artificial ceramic materials. Studying the acid resistance of proppants is important. Acids are needed to remove the scale and clays that affect the fracture conductivity.
This study investigated the different factors affecting the interactions between mud acid and sand proppants. Several experiments were conducted using the aging cell with mud acid (3 wt% HF, 12 wt% HCl) up to 300°F. The effects of temperature, soaking time, and static and dynamic conditions were examined. The supernatant of solubility tests was analyzed to measure total silicon concentrations using ICP-ES. The proppant was sieved before and after the experiments. Following that, the residual solids were dried and analyzed using a scanning electron microscope (SEM).
The results showed that sand proppant is soluble in regular mud acid, nearly 10 wt% dissolved in some cases. The amount of proppant dissolved increased with temperature, soaking time, concentration, and dynamic conditions. The fines generated and the changes in grain size distribution are detrimental to the proppant conductivity.
This work will help to achieve a better acid treatment design when sand proppant is used.
Korany, S. K. (Scimitar Production Egypt Ltd) | Hassan, W. (Scimitar Production Egypt Ltd) | Basta, G. S. (Scimitar Production Egypt Ltd) | Kortam, W. T. (Scimitar Production Egypt Ltd) | Coutry, S. N. (Scimitar Production Egypt Ltd) | Shokry, K. S. (Scimitar Production Egypt Ltd)
This paper describes a case study of cyclic group steaming of wells (CGSW) in a heavy oil (10-12 API) field located in Egypt. The field is known as Issaran with approximately 1.2 billion barrels of oil in place. CGSW was implemented in a pilot in a highly fractured limestone reservoir, with highly permeable fractures. During cyclic steam injection in the pilot, a negative effect was noticed during steam injection in some wells on surrounding wells; the gross production rate increased accompanied by an increase in water cut and wellhead temperature leading to loss in oil production. This meant that steam injection strategy needs some modifications
To avoid this, CGSW was implemented by applying steam cycles in all the producers of the pilots simultaneously, allowing for a better distribution of heat around all the wells.
Cyclic steam injection of all wells together implies pressurizing the reservoir, and hence increasing the reservoir energy along with decreasing the oil viscosity and enhancing the ultimate oil recovery. This, together with eliminating the negative effect of steam injection from the neighboring wells allowed the wells to show a better performance
Comparison is made between some of the wells producing before and after CGSW. The results are shown along with a full description of the process.
Worldwide water production (e.g. also called as un-wanted water) creates huge oil fields problems. An estimate shows that the average of three barrels of water is produced for each barrel of oil. The common practice in vertical wells is to block the water zone and perforate above. However, in horizontal zone if the oil-water contact (OWC) reaches the horizontal section, the well will be abandon. In literature, there are many methods used to delay water break though. Horizontal wells increase the potential of OWC movement due to the phenomena of high velocity of flow near heal compared to toe.
Horizontal wells have been increased significantly for last twenty years and almost replaced the vertical wells. Moreover, horizontal drilling has become a common practice with recent technology and advanced tools. As a result, the technology starts moving towards multilateral wells and extended reach drilling. In addition, some geological and reservoir cases put horizontal well in a challenging position. But still no one can deny advantages of horizontal wells and its contribution to the oil production and increasing exploited reserves. This article addresses the most exhibited challenges faced in horizontal well completions. In addition, the paper proposes the dual multilateral drilling and completion strategy and compares the proposed method with the conventional solution by ICDs and ICVs. A case study is also presented to show the effectiveness of the proposed strategy.
The problem with the existing practice is that the velocity of flow at heal is very high compared with the toe of a horizontal section. This situation causes many problems especially when there is permeability or pressure variations. It becomes even worst when the horizontal section is near the water- oil contact (OWC). The OWC below the horizontal section will be disturbed and this leads to early water break through. ICV is used to choke the heal area or some perforation design technique. All these techniques are based on reducing the production from that area. This article outlines how to tackle this issue using the proposed dual lateral completion while allowing the production to be increased within wider save margin. This method will be useful for enhancing the production and reducing the water break through for a reservoir.
Van Heekeren, H. (TAQA Energie B.V.) | Storm, R. (TAQA Energie B.V.) | Kraan, A. v. (Smith Bits, a Schlumberger Company) | Caycedo, A. (Smith Bits, a Schlumberger Company) | Maliekkal, H. (Smith Bits, a Schlumberger Company) | Azar, M. G. (Smith Bits, a Schlumberger Company) | White, A. (Smith Bits, a Schlumberger Company)
In The Netherlands the operator drilling in the Southern North Sea area had to drill through Germanic Trias super group sequences to the reservoir sections in Buntsandstein formations of lower Triassic series at a depth of about 9,800-ft TVD that are highly abrasive and hard sandstone formations. These formations are overlaid by middle and upper Triassic clay stones interbedded with hard dolomite stringers. The compressive strength of these formations ranges from 5,000–15,000 psi in the upper clay stones and from 15,000–30,000 psi in the Buntsandstein group.
Drilling the build and turn wellbore profiles using a directional BHA with roller cone and/or PDC has been challenging. In offsets, these bit types produced slow ROP and short run lengths, requiring multiple bit trips to complete the hole section. In many cases, the bits were pulled in poor dull condition with severe cutting structure damage. In some cases, the operator was forced to use diamond-impregnated bits on turbine to TD the section.
To drill the section in one run and at higher ROP, the provider recommended a new-style conical diamond element bit that uses multiple conical shaped diamond elements (CDEs) positioned from bit center to gauge. The CDE's conical shape penetrates high-compressive-strength rock with a concentrated point loading that fails formation with a plowing mechanism. Design engineers used a finite-element-analysis (FEA)-based modeling system to strategically place the CDEs based on specific drilling parameters and formation characteristics. Recent R&D tests confirm the hybrid PDC bit drills with 25% less torque compared with conventional PDC cutters, providing increased directional control and smoother toolface response. The result is higher build rates that achieve directional objectives in less time. The new 513 design also included a centrally located CDE to enhance bit stability and mitigate shock and vibration.
The bit was run on an RSS BHA and drilled 1,279 ft of difficult claystone and anhydrite/dolomite with silt/sandstone stringers at an average ROP of 31.04 ft/hr, 200% faster compared to the closest offsets in the reservoir sand. The bit also set a new single-run footage benchmark for this section in Block P15. The RSS BHA efficiently delivered all directional wellbore requirements, building inclination from 26° to 39° with a DLS of 3.42°/100 ft and 6.09°/100 ft in Sidetrack 1. As a result, the operator saved one day of rig time and a bit trip for a total savings of approximately USD 635,000.
When cementing liners, the cement must develop compressive strength at the top of the liner before drilling is resumed. Sometimes at high temperature wells, it can take us up to 2 days just waiting for compressive strength development at top of liner conditions. This problem is common when cementing long liners in high temperature wells.
An earlier study done by Yami et al. (2007) showed the development of two new retarded systems. The first system is used for non-latex cements for wells that do not show indications of fluid flow. The second cement system includes latex and is recommended for liners with potential for fluid flow. The new retarder systems were effectively applied in a well in Red Sea. This paper discusses the non-latex system field application and summarizes lessons learned.
The field application was done by using sodium salt and alicyclic acid with aminated aromatic polymer in combination with sodium salt of organic acid and inorganic salt and aromatic polymer derivatives to cover differential temperature of more than 100 °F.
Nassar, Mohamed (Petrobel-belayem Petroleum Company) | Matresu, Justin (Petrobel-belayem Petroleum Company) | Talat, Amr (Petrobel-belayem Petroleum Company) | Hasan, Motaz (Petrobel-belayem Petroleum Company)
Nile Delta Basin is a mature gas producer in Egypt, from the early sixties till present many gas discoveries were made in both on & offshore areas in the Pliocene and Miocene reservoirs. The first gas field, Abu Madi Field, was discovered onshore Nile Delta in 1967, by AGIP (IEOC) with the drilling of the Abu Madi-1 (AM-1) well. The Abu Madi field started to be developed since 1970, it's producing wells increased to 21 and by end-1992, the field had a capacity of 400 MCF/d; being that time the biggest gas field in Egypt. Subsequently of the gas-bearing reservoir discovered in Abu Madi Formation (Late Messinian) - becomes one of the main targets in on and offshore area of Nile Delta. The stratigraphic framework of the Abu Madi Fm., was reveal through years, now a days this formation is considerate as a sedimentary infilling of a fluvial paleovalley characterized by stacked fluvial-deltaic sandstone and shale's. The classical Abu Madi Fm., lithostratigraphic layering comes from the Abu Madi/El Qaraa fields where the reservoirs sandstones levels have been named, starting from bottom, as follows: Level 3 (Lower, Main, Upper and 3A), Lev2 and Lev 1. The recently wells targeting the Lev 3 Main and Lev 3A reservoirs did not achieved the estimated remaining recoverable resources. In this study the new 3D seismic data, production history and petrophysical data were integrated in order to relocate the unachieved residual OGIP and also to find new drilling opportunities for additional potential resources.